### 6698 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

ENVIRONMENTAL PROTECTION
AGENCY

40 CFR Parts 80, 85, and 86

[AMS–FRL–6516–2]

RIN 2060–AI23

Control of Air Pollution From New

Motor Vehicles: Tier 2 Motor Vehicle
Emissions Standards and Gasoline Sulfur Control Requirements

AGENCY : Environmental Protection Agency (EPA).

ACTION : Final rule.

SUMMARY : Today’s action finalizes a major program designed to significantly
reduce the emissions from new passenger cars and light trucks, including pickup trucks, vans, minivans, and sport-utility vehicles. These reductions will provide for cleaner air and greater public health protection, primarily by reducing ozone and PM pollution. The program is a comprehensive regulatory initiative that treats vehicles and fuels as a system, combining requirements for much cleaner vehicles with requirements for much lower levels of sulfur in gasoline. A list of major highlights of the program appears at the beginning of the

SUPPLEMENTARY INFORMATION section of
this Federal Register

.

The program we are finalizing today will phase in a single set of tailpipe emission standards that will, for the first time, apply to all passenger cars, light trucks, and larger passenger vehicles operated on any fuel. This set of ‘‘Tier
2 standards’’ is feasible and the use of a single set of standards is appropriate because of the increased use of light trucks for personal transportation. The miles traveled in light trucks is increasing and the emissions from these vehicles are thus an increasing problem. This approach builds on the recent technology improvements resulting
from the successful National LowEmission Vehicles (NLEV) program.

To enable the very clean Tier 2 vehicle emission control technology to
be introduced and to maintain its effectiveness, we are also requiring reduced gasoline sulfur levels
nationwide. The reduction in sulfur levels will also contribute directly to
cleaner air in addition to its beneficial
effects on vehicle emission control systems. Refiners will generally install additional refining equipment to remove sulfur in their refining processes. Importers of gasoline will be required to import and market only gasoline meeting the sulfur standards. Today’s action also introduces an averaging, banking, and trading program to provide flexibility for refiners and ease implementation of the gasoline sulfur control program.

The overall program focuses on reducing the passenger car and light truck emissions most responsible for causing ozone and particulate matter problems. Without today’s action, we project that emissions of nitrogen oxides from these vehicles will represent asmuch as 40 percent of this ozoneforming pollutant in some cities, and almost 20 percent nationwide, by the
year 2030.

Today’s program will bring about major reductions in annual emissions of these pollutants and also reduce the emissions of sulfur compounds resulting from the sulfur in gasoline. For example, we project a reduction in oxides of nitrogen emissions of at least 856,000 tons per year by 2007 and 1,236,000 by 2010, the time frame when many states will have to demonstrate compliance with air quality standards.
Emission reductions will continue increasing for many years, reaching at least 2,220,000 tons per year in 2020 and continuing to rise further in future years. In addition, the program will
reduce the contribution of vehicles to other serious public health and environmental problems, including VOC, PM, and regional visibility problems, toxic air pollutants, acid rain, and nitrogen loading of estuaries.

Furthermore, we project that these reductions, and their resulting environmental benefits, will come at an average cost increase of less than $100 per passenger car, an average cost increase of less than $200 for light trucks, and an average cost increase of about $350 for medium-duty passenger vehicles, and an average increase of less than 2 cents per gallon of gasoline (or about $120 over the life of an average vehicle).

DATES : This rule is effective April 10,

2000.

The incorporation by reference of certain publications contained in this rule are approved by the Director of the Federal Register as of April 10, 2000.

ADDRESSES : Comments: All comments and materials relevant to today’s action have been placed in Public Docket No. A–97–10 at the following address: U.S. Environmental Protection Agency (EPA), Air Docket (6102), Room M– 1500, 401 M Street, S.W., Washington,
D.C. 20460. EPA’s Air Docket makes materials related to this rulemaking
available for review at the above address (on the ground floor in Waterside Mall) from 8:00 a.m. to 5:30 p.m., Monday through Friday, except on government holidays. You can reach the Air Docket by telephone at (202) 260–7548 and by facsimile at (202) 260–4400. We may charge a reasonable fee for copying docket materials, as provided in 40 CFR

Part 2.

FOR FURTHER INFORMATION CONTACT : Carol Connell, U.S. EPA, National Vehicle and Fuels Emission Laboratory, 2000 Traverwood, Ann Arbor MI 48105; Telephone (734) 214–4349, FAX (734) 214–4816, E-mail connell.carol@epa.gov.

SUPPLEMENTARY INFORMATION :
Highlights of the Tier2/Gasoline Sulfur Program

For cars, and light trucks, and larger passenger vehicles, the program will—

• Starting in 2004, through a phasein, apply for the first time the same set of emission standards covering passenger cars, light trucks, and large SUVs and passenger vehicles. These emission levels (‘‘Tier 2 standards’’) are
feasible for these vehicles. The Tier 2 standards are also appropriate because of the increased use of light trucks for personal transportation—the miles traveled in light trucks is increasing and
the emissions from these vehicles are thus an increasing problem.

• Introduce a new category of vehicles, ‘‘medium-duty passenger vehicles,’’ thus bringing larger passenger vans and SUVs into the Tier 2 program.

• During the phase-in, apply interim fleet emission average standards that match or are more stringent than currentfederal and California ‘‘LEV I’’ (LowEmission Vehicle, Phase I) standards.

• Apply the same standards to vehicles operated on any fuel.

• Allow auto manufacturers to comply with the very stringent new standards in a flexible way while ensuring that the needed environmental
benefits occur.

• Build on the recent technology improvements resulting from the
successful National Low-Emission Vehicles (NLEV) program and improve the performance of these vehicles through lower sulfur gasoline.

• Set more stringent particulate
matter standards.

• Set more stringent evaporative
emission standards.

For commercial gasoline, the program
will—

• Significantly reduce average gasoline sulfur levels nationwide as early as 2000, fully phased in in 2006. Refiners will generally add refining equipment to remove sulfur in their refining processes. Importers of gasoline will be required to import and market only gasoline meeting the sulfur limits.


### 6699 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

• Provide for flexible implementation by refiners through an averaging, banking, and trading program.

• Encourage early introduction of cleaner fuel into the marketplace through an early sulfur credit and allotment program.

• Apply temporary gasoline sulfur
standards to certain small refiners and gasoline marketed in a limited geographic area in the western U.S.

• Enable the new Tier 2 vehicles to meet the emission standards by greatly reducing the degradation of vehicle emission control performance from sulfur in gasoline. Lower sulfur gasoline also appears to be necessary for the introduction of advanced technologies that promise higher fuel economy but are very susceptible to sulfur poisoning (for example, gasoline direct injection engines).

• Reduce emissions from NLEV vehicles and other vehicles already on
the road.

Regulated Entities

This action will affect you if you produce new motor vehicles, alter individual imported motor vehicles to address U.S. regulation, or convert

motor vehicles to use alternative fuels. It will also affect you if you produce, distribute, or sell gasoline motor fuel.

The table below gives some examples of entities that may have to comply with the regulations. But because these are only examples, you should carefully examine these and existing regulations in 40 CFR parts 80 and 86. If you have questions, call the person listed in the

FOR FURTHER INFORMATION CONTACT section above.

Category NAICS codes a SIC Codes b Examples of potentially regulated entities

Industry ......................................................................... 336111 3711 Motor Vehicle Manufacturers.

336112

336120 Industry ......................................................................... 336311 3592 Alternative fuel vehicle converters.

336312 3714

422720 5172

454312 5984

811198 7549

541514 8742

541690 8931 Industry ......................................................................... 811112 7533 Commercial Importers of Vehicles andVehicle Components.

811198 7549

541514 8742 Industry ......................................................................... 324110 2911 Petroleum Refiners. Industry ......................................................................... 422710 5171 Gasoline Marketers and Distributors.

422720 5172 Industry ......................................................................... 484220 4212 Gasoline Carriers.

484230 4213

a North American Industry Classification System (NAICS).

b Standard Industrial Classification (SIC) system code.

Access to Rulemaking Documents Through the Internet

Today’s action is available electronically on the day of publication from the Office of the Federal Register
Internet Web site listed below. Electronic copies of this preamble and regulatory language as well as the Response to Comments document, the Regulatory Impact Analysis and other documents associated with today’s final
rule are available from the EPA Office
of Mobile Sources Web site listed below shortly after the rule is signed by the
Administrator. This service is free of charge, except any cost that you already incur for connecting to the Internet. Federal Register Web Site: http://

www.epa.gov/docs/fedrgstr/epa-air/ (Either select a desired date or use the Search feature.) Office of Mobile Sources (OMS) Web

Site: http://www.epa.gov/oms/ (Look
in ‘‘What’s New’’ or under the ‘‘Automobiles’’ topic.)

Please note that due to differences between the software used to develop
the document and the software into which the document may be downloaded, changes in format, page length, etc., may occur.

Outline of This Preamble

I. Introduction

A. What Are the Basic Components of the

Program?
1. Vehicle Emission Standards

2. Gasoline Sulfur Standards B. What Is Our Statutory Authority for

Today’s Action? 1. Light-Duty Vehicles and Trucks

2. Gasoline Sulfur Controls C. The Tier 2 Study and the Sulfur Staff

Paper D. Relationship of Diesel Fuel Sulfur

Control to the Tier 2/Gasoline Sulfur Program

II. Tier 2 Determination

A. There Is a Substantial Need for Further

Emission Reductions in Order To Attain

and Maintain National Ambient Air Quality Standards B. More Stringent Standards for Light-Duty

Vehicles and Trucks Are Technologically

Feasible C. More Stringent Standards for Light-Duty

Vehicles and Trucks Are Needed and Cost Effective Compared to Available

Alternatives III. Air Quality Need For and Impact of Today’s Action A. Americans Face Serious Air Quality Problems That Require Further Emission
Reductions

B. Ozone 1. Background on Ozone Air Quality
2. Additional Emission Reductions Are

Needed To Attain and Maintain the Ozone NAAQS. a. Summary b. Ozone Modeling Presented in Our

Proposal and Supplemental Notice c. Updated and Additional Ozone

Modeling
d. Results and Conclusions
e. Issues and Comments Addressed
f. 8-Hour Ozone 3. Cars and Light-Duty Trucks Are a Big

Part of the NO X and VOC Emissions, and Today’s Action Will Reduce This Contribution Substantially 4. Ozone Reductions Expected From This

Rule
C. Particulate Matter 1. Background on PM
2. Need for Additional Reductions to

Attain and Maintain the PM 10 NAAQS

3. PM25 Discussion
4. Emission Reductions and Ambient PM

Reductions
D. Other Criteria Pollutants: Carbon

Monoxide, Nitrogen Dioxide, Sulfur
Dioxide E. Visibility


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F. Air Toxics G. Acid Deposition H. Eutrophication/Nitrification I. Cleaner Cars and Light Trucks Are

Critically Important to Improving Air Quality IV. What Are the New Requirements for
Vehicles and Gasoline? A. Why Are We Proposing Vehicle and

Fuel Standards Together? 1. Feasibility of Stringent Standards for

Light-Duty Vehicles and Light-Duty
Trucks a. Gasoline Fueled Vehicles i.
LDVs and LDT1s–LDT4s ii. MediumDuty Passenger Vehicles (MDPVs) b.
Diesel Vehicles
2. Gasoline Sulfur Control Is Needed To

Support the Proposed Vehicle Standards
a. How Does Gasoline Sulfur Affect
Vehicle Emission Performance? b. How Large Is Gasoline Sulfur’s Effect on Emissions? c. Sulfur’s Negative Impact on Tier 2 Catalysts d. Sulfur Has Negative Impacts on OBD Systems B. Our Program for Vehicles 1. Overview of the Vehicle Program a.

Introduction b. Corporate Average NOx
Standard c. Tier 2 Exhaust Emission
Standard ‘‘Bins’ d. Schedules for Implementation i. Implementation
Schedule for Tier 2 LDVs and LLDTs ii. Implementation Schedule for Tier 2
HLDTs e. Interim Standards i. Interim
Exhaust Emission Standards for LDV/
LLDTs ii Interim Exhaust Emission
Standards for HLDTs iii. Interim Programs Will Provide Reductions Over Previous Standards f. Generating, Banking, and Trading NOx Credits 2. Why Are We Finalizing the Same Set of

Standards for Tier 2 LDVs and LDTs? 3. Why Are We Finalizing the Same

Standards for Both Gasoline and Diesel
Vehicles? 4. Key Elements of the Vehicle Program a.

Basic Exhaust Emission Standards and ‘‘Bin’’ Structure i. Why Are We Including Extra Bins? b. The Program
Will Phase In the Tier 2 Vehicle Standards Over Several Years i. Primary
Phase-in Schedule
ii. Alternative Phase-in Schedule c. Manufacturers Will Meet a ‘‘Corporate

Average’’ NO X Standard d. Manufacturers Can Generate, Bank, and

Trade NO X Credits
i. General Provisions ii. Averaging, Banking and Trading of NO X

Credits Fulfills Several Goals
iii. How Manufacturers Can Generate and

Use NO X Credits
iv. Manufacturers Can Earn and Bank

Credits for Early NO X Reductions

v. Tier 2 NO X Credits Will Have Unlimited

Life

vi. NO X Credit Deficits Can Be Carried

Forward vii. Encouraging the Introduction of Ultra

Clean Vehicles
e. Interim Standards
i. Interim Exhaust Emission Standards for

LDV/LLDTs
ii. Interim Exhaust Emission Standards for

HLDTs f. Light-Duty Evaporative Emission

Standards g. Passenger Vehicles Above 8,500 Pounds

GVWR C. Our Program for Controlling Gasoline

Sulfur
1. Gasoline Sulfur Standards for Refiners

and Importers
a. Standards and Deadlines That Refiners/

Importers Must Meet i. What Are the Per-Gallon Caps on

Gasoline Sulfur Levels in 2004 and Beyond?
ii. What Standards Must Refiners/

Importers Meet on a Corporate Average

Basis? iii. What Standards Must Be Met by

Individual Refineries/Importers?
b. Standards and Deadlines for Refiners/

Importers Which Provide Gasoline to the Geographic Phase-in Area (GPA) i. Justification for Our Geographic Phase-in

Approach ii. What Is the Geographic Phase-in Area

and How Was It Established?
iii. Standards/Deadlines for Gasoline Sold

in the Geographic Phase-in Area iv. What Are the Per-Gallon Caps on

Gasoline Sulfur Levels in the Phase-in

Area? v. How Do Refiners/Importers Account for

GPA Fuel in Their Corporate Average
Calculations? vi. How Do Refiners/Importers Apply for

the Geographic Phase-in Area Standards?
vii. How Will EPA Establish the GPA in

Adjacent States? c. How Does the Sulfur Averaging,

Banking, and Trading Program Work? i. Generating Allotments Prior to 2004 ii. Generating Allotments in 2004 and 2005 iii. Using Allotments in 2004 and 2005 iv. How Long Do Allotments Last? v. Establishing Individual Refinery Sulfur

Baselines for Credit Generation Purposes vi. Generating Sulfur Credits Prior to 2004 vii. Generating Sulfur Credits in 2004 and

Beyond viii. Using Sulfur Credits ix. How Long Do Credits Last?
x. Conversion of Allotments Into Credits d. How are State Sulfur Programs Affected

by EPA’s Program? 2. Hardship Provision for Qualifying

Refiners a. Hardship Provision for Qualifying Small

Refiners
i. How Are Small Refiners Defined?
ii. Standards That Small Refiners Must

Meet iii. How Do Small Refiners Apply for Small

Refiner Status? iv. How Do Small Refineries Apply for a

Sulfur Baseline?
v. Volume Limitation on Use of a Small

Refinery Standard vi. Extensions Beyond 2007 for Small

Refiners vii. Can Small Refiners Participate in the

ABT Program? b. Temporary Waivers From Low Sulfur

Requirements in Extreme Unforeseen

Circumstances c. Temporary Waivers Based on Extreme

Hardship Circumstances 3. Streamlining of Refinery Air Pollution

Permitting Process a. Brief Summary of Proposal b. Significant Comments Received c. Today’s Action i. Major New Source Review ii. Environmental Justice D. What Are the Economic Impacts, Cost

Effectiveness and Monetized Benefits of the Tier 2 Program?
1. What Are the Estimated Costs of the

Vehicle Standards?
2. Estimated Costs of the Gasoline Sulfur

Standards 3. What Are the Aggregate Costs of the Tier

2/Gasoline Sulfur Final Rule?
4. How Does the Cost-Effectiveness of This

Program Compare to Other Programs? a. Cost Effectiveness of this Program
b. How Does the Cost Effectiveness of This

Program Compare With Other Means of Obtaining Mobile Source NO X+NMHC
Reductions?
c. How Does the Cost Effectiveness of This

Program Compare With Other Known Non-Mobile Source Technologies for Reducing NO X+NMHC? 5. Does the Value of the Benefits Outweigh

the Cost of the Standards? a. What Is the Purpose of This Benefit-Cost

Comparison? b. What Was Our Overall Approach to the

Benefit-Cost Analysis? c. What Are the Significant Limitations of

the Benefit-Cost Analysis? d. How Was the Benefit-Cost Analysis

Changed From Proposal?
e. How Did We Perform the Benefit-Cost

Analysis?
f. What Were the Results of the BenefitCost Analysis?
V. Other Vehicle-Related Provisions

A. Final Tier 2 CO, HCHO and PM

Standards 1. Carbon Monoxide (CO) Standards 2. Formaldehyde (HCHO) Standards 3. Use of NMHC Data To Show Compliance

With NMOG Standards; Alternate Compliance With Formaldehyde
Standards. 4. Particulate Matter (PM) Standards
B. Useful Life 1. Mandatory 120,000 Mile Useful Life 2. 150,000 Mile Useful Life Certification

Option C. Supplemental Federal Test Procedure

(SFTP) Standards 1. Background 2. SFTP Under the NLEV Program
3. SFTP Standards for the Interim and Tier

2 LDVs and LDTs: As Proposed
4. Final SFTP Standards for Interim and

Tier 2 LDVs and LDTs 5. Adding a PM Standard to the SFTP

Standards
6. Future Efforts Relevant to SFTP

Standards D. LDT Test Weight
E. Test Fuels F. Changes to Evaporative Certification

Procedures to Address Impacts of
Alcohol Fuels
G. Other Test Procedure Issues
H. Small Volume Manufacturers 1. Special Provisions for Independent

Commercial Importers (ICIs) 2. Hardship Provision for Small Volume

Manufacturers I. Compliance Monitoring and Enforcement


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1. Application of EPA’s Compliance

Assurance Program, CAP2000 2. Compliance Monitoring

3. Relaxed In-Use Standards for Vehicles

Produced During the Phase-in Period

4. Enforcement of the Tier 2 and Interim

Corporate Average NO X Standards. J. Addressing Environmentally Beneficial

Technologies Not Recognized by Test

Procedures K. Adverse Effects of System Leaks L. The Future Development of Advanced

Technology and the Role of Fuels

M. Miscellaneous Provisions VI. Gasoline Sulfur Program Compliance

and Enforcement Provisions

A. Overview B. Requirements for Foreign Refiners and

Importers 1. Requirements for Foreign Refiners With

Individual Refinery Sulfur Standards or

Credit Generation Baselines 2. Requirements for Truck Importers C. What Standards and Requirements

Apply Downstream? D. Testing and Sampling Methods and

Requirements
1. Test Method for Sulfur in Gasoline

2. Test Method for Sulfur in Butane 3. Quality Assurance Testing 4. Requirement to Test Every Batch of

Gasoline Produced or Imported 5. Exceptions to the Every-Batch Testing

Requirement 6. Sampling Methods 7. Gasoline Sample Retention

Requirements
E. Federal Enforcement Provisions for

California Gasoline and for Use of

California Test Methods to Determine Compliance F. Recordkeeping and Reporting

Requirements
1. Product Transfer Documents 2. Recordkeeping Requirements 3. Reporting Requirements G. Exemptions for Research, Development,

and Testing H. Liability and Penalty Provisions for

Noncompliance I. How Will Compliance With the Sulfur

Standards Be Determined? VII. Public Participation VIII. Administrative Requirements

A. Administrative Designation and

Regulatory Analysis B. Regulatory Flexibility 1. Potentially Affected Small Businesses 2. Small Business Advocacy Review Panel

and the Evaluation of Regulatory

Alternatives C. Paperwork Reduction Act D. Intergovernmental Relations

1. Unfunded Mandates Reform Act

2. Executive Order 13084: Consultation

and Coordination With Indian Tribal

Governments 3. Executive Order 13132 (Federalism) E. National Technology Transfer and

Advancement Act

F. Executive Order 13045: Children’s

Health Protection G. Congressional Review Act IX. Statutory Provisions and Legal Authority I. Introduction

Since the passage of the 1990 Clean Air Act Amendments, the U.S. has made significant progress in reducing emissions from passenger cars and light
trucks. The National Low-Emission Vehicle (NLEV) and Reformulated Gasoline (RFG) programs are important examples of control programs that are in place and will continue to help reduce car and light-duty truck emissions into
the near future.

Nonetheless, due to increasing vehicle population and vehicle miles traveled, passenger cars and light trucks will continue to be significant contributors to air pollution inventories well into the future. In fact, the emission contribution of light trucks and sport utility vehicles now matches that of passenger cars. (This is occurring because of the combination of growth in miles traveled by light trucks and the fact that their emission standards are currently less stringent than those of passenger cars). The program we describe below builds on the NLEV and RFG Phase II programs to develop a strong new national program to protect public health and the environment well into the next century. The program, while reducing VOC and other emissions, focuses especially on

NO X , because that is where the largest air quality gains can be achieved.

We have followed several overarching principles in developing this final rule:

• Design a strong national program that will assist states in every region of the country to meet their air quality objectives and that will ensure that cars
and trucks continue to contribute a fair share to our nation’s overall air quality solutions;

• View vehicles and fuels as an integrated system, recognizing that only by addressing both can the best overall emission performance be achieved;

• Establish a single set of emission standards that apply regardless of the
fuel used and whether the vehicle is a car, a light truck, or a larger passenger vehicle;

• Provide compliance flexibilities
that allow vehicle manufacturers and oil refiners to adjust to future market trends and honor consumer preferences;

• Not preclude the development of
advanced low emission or fuel efficient technologies such as lean-burn engines;
and

• Ensure sufficient leadtime for phase-in of the Tier 2 and gasoline sulfur program.

With these principles as background,
we turn now to an overview of the vehicle and fuel aspects of the program. Sections I and II of this preamble will give you a brief overview of our program and our rationale for implementing it. Subsequent sections will expand on the air quality need, technological feasibility, economic impacts, and provide a detailed description of the specifics of the program. A public participation section reviews the process we followed in soliciting and responding to public comment. The
final sections deal with several administrative requirements. You may also want to review our Final Regulatory Impact Analysis (RIA) and our Response to Comments document, both of which
are found in the docket and on the Internet. They provide additional analyses and discussions of many topics raised in this preamble.

A. What Are the Basic Components of the Program?

The nation’s air quality, while certainly better than in the past, will nevertheless continue to expose tens of millions of Americans to unhealthy levels of air pollution well into the future in the absence of significant new
controls on emissions from motor vehicles. EPA is therefore finalizing a major, comprehensive program designed
to reduce emission standards for passenger cars, light trucks, and largepassenger vehicles (including sportutility vehicles, minivans, vans, and pickup trucks) and to reduce the sulfur content of gasoline. Under the program, automakers will produce vehicles designed to have very low emissions when operated on low-sulfur gasoline, and oil refiners will provide that much cleaner gasoline nationwide. In this preamble, we refer to the comprehensive program as the ‘‘Tier 2/ Gasoline Sulfur program.’’

1. Vehicle Emission Standards

Today’s action sets new federal emission standards (‘‘Tier 2 standards’’) for passenger cars, light trucks, and larger passenger vehicles. The program is designed to focus on reducing the emissions most responsible for the ozone and particulate matter (PM) impact from these vehicles—nitrogen oxides (NO X) and non-methane organic gases (NMOG), consisting primarily of hydrocarbons (HC) and contributing to ambient volatile organic compounds (VOC). The program will also, for the first time, apply the same set of federal standards to all passenger cars, light trucks, and medium-duty passenger vehicles. Light trucks include ‘‘light light-duty trucks’’ (or LLDTs), rated at less than 6000 pounds gross vehicle weight and ‘‘heavy light-duty trucks’’ (or HLDTs), rated at more than 6000


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1 A vehicle’s ‘‘Gross Vehicle Weight Rating,’’ or GVWR, is the curb weight of the vehicle plus its maximum recommended load of passengers and

cargo.

2 By comparison, the NO X standards for the National Low Emission Vehicle (NLEV) program, which will be in place nationally in 2001, range from 0.30 g/mi for passenger cars to 0.50 g/mi for medium-sized light trucks (larger light trucks are not covered). For further comparison, the standards met by today’s Tier 1 vehicles range from 0.60 g/ mi to 1.53 g/mi.

3 There are also NMOG standards associated with

both the interim and Tier 2 standards. The NMOG standards vary depending on which of various

individual sets of emission standards manufacturers choose to use in complying with the average NO X standard. This ‘‘bin’’ approach is described more fully in section IV.B. of this preamble. 4 LDTs with a loaded vehicle weight less than or equal to 3750 pounds, called LDT1s and LDT2s.

5 Section 202(b)(1)(C) forbids EPA from promulgating mandatory standards more stringent than Tier 1 standards until the 2004 model year. pounds gross vehicle weight). 1 ‘‘Medium-duty passenger vehicles’’ (or MDPVs) form a new class of vehicles introduced by this rule that includes SUVs and passenger vans rated at between 8,500 and 10,000 GVWR. The program thus ensures that essentially all vehicles designed for passenger use in the future will be very clean vehicles.

The Tier 2 standards finalized today
will reduce new vehicle NO X levels to an average of 0.07 grams per mile (g/mi). For new passenger cars and light LDTs, these standards will phase in beginning in 2004, with the standards to be fully phased in by 2007. 2 For heavy LDTs and MDPVs, the Tier 2 standards will be phased in beginning in 2008, with full compliance in 2009.

During the phase-in period from 2004–2007, all passenger cars and light LDTs not certified to the primary Tier 2
standards will have to meet an interim average standard of 0.30 g/mi NOX , equivalent to the current NLEV standards for LDVs and more stringent than NLEV for LDT2s (e.g., minivans). 3 During the period 2004–2008, heavy
LDTs and MDPVs not certified to the final Tier 2 standards will phase in to an interim program with an average standard of 0.20 g/mi NO X , with those not covered by the phase-in meeting a per-vehicle standard (i.e., an emissions ‘‘cap’’) of 0.6 g/mi NO X (for HLDTs) and 0.9 g/mi NO X (for MDPVs). The average
standards for NO X will allow manufacturers to comply with the very stringent new standards in a flexible way, assuring that the average emissions of a company’s production meet the target emission levels while allowing
the manufacturer to choose from several more- and less-stringent emission categories for certification.

We are also setting stringent particulate matter standards that will be especially important if there is substantial future growth in the sales of diesel vehicles. Before 2004, we are establishing more stringent interim PM standards for most light trucks than exist now under NLEV. With higher sales of diesel cars and light trucks, theycould easily contribute between onehalf and two percent of the PM10 concentration allowed by the NAAQS, with some possibility that the contribution could be as high as 5 to 40 percent in some roadside situations with heavy traffic. These increases
would make attainment even more
difficult for 8 counties which we already predict to need further emission
reductions even without an increase in diesel sales, and would put at risk
another 18 counties which are now within 10 percent of a NAAQS violation. Thus, by including a more stringent PM standard in the program finalized today, we help address
environmental concerns about the potential growth in the numbers of light-duty diesels on the road—even if that growth is substantial. The new requirements also include more stringent hydrocarbon controls (exhaust NMOG and evaporative emissions standards). We will also monitor the progress of the development of advanced technologies and the role of
fuels.

2. Gasoline Sulfur Standards

The other major part of today’s action will significantly reduce average gasoline sulfur levels nationwide. We expect these reductions could begin to phase in as early as 2000, with full compliance for most refiners occurring by 2006. Refiners will generally install advanced refining equipment to remove sulfur during the production of gasoline. Importers of gasoline will be required to import and market only gasoline meeting the sulfur limits. Temporary, less stringent standards will apply to a few small refiners through 2007. In addition, temporary, less stringent standards will apply to a limited geographic area in the western U.S. for the 2004–2006 period.

This significant new control of gasoline sulfur content will have two important effects. The lower sulfur levels will enable the much-improved emission control technology necessary to meet the stringent vehicle standards of today’s rule to operate effectively
over the useful life of the new vehicles. In addition, as soon as the lower sulfur gasoline is available, all gasoline vehicles already on the road will have
reduced emissions—from less degradation of their catalytic converters and from fewer sulfur compounds in the
exhaust.

Today’s action will encourage refiners to reduce sulfur in gasoline as early as 2000. The program requires that most refiners and importers meet a corporate average gasoline sulfur standard of 120 ppm and a cap of 300 ppm beginning in 2004. By 2006, the cap will be reduced to 80 ppm and most refineries must produce gasoline averaging no more than 30 ppm sulfur. The program builds upon the existing regulations covering gasoline composition as it relates to emissions performance. It includes provisions for trading of sulfur credits, increasing the flexibility available to refiners for complying with the new requirements. We intend for the credit program to ease compliance uncertainties by providing refiners the flexibility to phase in early controls in 2000–2003 and use credits gained in these years to delay some control until as late as 2006. As finalized today, the program will achieve the needed environmental benefits while providing substantial flexibility to refiners.

B. What Is Our Statutory Authority for Today’s Action?

1. Light-Duty Vehicles and Trucks

We are setting motor vehicle emission standards under the authority of section 202 of the Clean Air Act. Sections 202(a) and (b) of the Act provide EPA with general authority to prescribe vehicle standards, subject to any specific
limitations otherwise included in the Act. Sections 202(g) and (h) specify the current standards for LDVs and LDTs, which became effective beginning in model year 1994 (‘‘Tier 1 standards’’).

Section 202(i) of the Act provides specific procedures that EPA must
follow to determine whether standards more stringent than Tier 1 standards for
LDVs and certain LDTs 4 are appropriate beginning between the 2004 and 2006 model years. 5 Specifically, we are required to first issue a study regarding
‘‘whether or not further reductions in emissions from light-duty vehicles and light-duty trucks should be required * * *’’ (the ‘‘Tier 2 Study’’). This study
‘‘shall examine the need for further
reductions in emissions in order to
attain or maintain the national ambient air quality standards.’’ It is also to consider: (1) The availability of technology to meet more stringent standards, taking cost, lead time, safety, and energy impacts into consideration; and (2) the need for, and cost effectiveness of, such standards, including consideration of alternative methods of attaining or maintaining the national ambient air quality standards.
A certain set of ‘‘default’’ emission


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6 LDTs that have gross vehicle weight ratings above 6000 pounds are considered ‘‘heavy-duty vehicles’’ under the Act. See section 202(b)(3). For regulatory purposes, we refer to these LDTs as ‘‘heavy light-duty trucks’’ made up of LDT3s and

LDT4s.

7 We currently have regulatory requirements for conventional and reformulated gasoline adopted under Sections 211(c) and 211(k) of the Act, in addition to the ‘‘substantially similar’’ requirements for fuel additives of Section 211(f). These requirements have the effect of limiting sulfur levels in gasoline to some extent. See the Final RIA
for more details. 8 On April 28, 1998, EPA published a notice of availability announcing the release of a draft of the Tier 2 study and requesting comments on the draft. The final report to Congress included a summary and analysis of the comments EPA received. standards for these vehicle classes is among those options for new standards
that EPA is to consider.

After the study is completed and the results are reported to Congress, EPA is required to determine by rulemaking whether: (1) There is a need for further emission reductions; (2) the technology for more stringent emission standards from the affected classes is available; and (3) such standards are needed and cost-effective, taking into account alternatives. If EPA answers ‘‘yes’’ to these questions, then the Agency is to promulgate new, more stringent motor vehicle standards (‘‘Tier 2 standards’’).

EPA submitted its report to Congress on July 31, 1998. Today’s final rule makes affirmative responses to the three questions above (see Section II below)
and sets new standards that are more stringent than the default standards in
the Act.

EPA is also setting standards for larger light-duty trucks and MDPVs under the general authority of Section 202(a)(1) and 202(b) and under Section 202(a)(3) of the Act, which requires that standards applicable to emissions of hydrocarbons, NO X , CO and PM from heavy-duty vehicles 6 reflect the greatest degree of emission reduction available for the model year to which such standards apply, giving appropriate consideration to cost, energy, and safety. We are also setting standards for formaldehyde under our authority in sections 202(a) and (l).

2. Gasoline Sulfur Controls

We are adopting gasoline sulfur controls pursuant to our authority under Section 211(c)(1) of the Clean Air Act. 7 Under Section 211(c)(1), EPA may adopt
a fuel control if at least one of the following two criteria is met: (1) The emission products of the fuel cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare; or (2) the emission products of the fuel will significantly impair emissions control systems in general use or which will be in general use were the fuel control to be adopted.

We are adopting gasoline sulfur
controls based on both of these criteria. Under the first criterion, we believe that sulfur in gasoline used in Tier 1 and LEV technology vehicles contributes to ozone pollution, air toxics, and PM. Under the second criterion, we believe that gasoline sulfur in fuel will significantly impair the emissions control systems expected to be used in Tier 2 technology vehicles, as well as emissions control systems currently
used in LEVs. Please refer to Section IV.C. below and to the Final Regulatory Impact Analysis (RIA) for more details of our analysis and findings. The RIA
includes a more detailed discussion of EPA’s authority to set gasoline sulfur standards, including a discussion of our conclusions relating to the factors required to be considered under Section 211(c).

C. The Tier 2 Study and the Sulfur Staff Paper

On July 31, 1998, EPA submitted its report to Congress containing the results of the Tier 2 study. 8 The study indicated that in the 2004 and later time frame,
there will be a need for emission reductions to aid in meeting and maintaining the National Ambient Air Quality Standards (NAAQS) for both ozone and PM. Air quality modeling
showed that in the 2007–2010 time frame, when Tier 2 standards will become fully effective, a number of
areas will still be in nonattainment for
ozone and PM even after the implementation of existing emission controls. The study also noted the
continued existence of carbon monoxide (CO) nonattainment areas. It also found ample evidence that technologies will be available to meet more stringent Tier 2 standards. In addition, the study provided evidence that such standards could be implemented at a similar cost per ton of reduced pollutants as other programs aimed at similar air quality problems. Finally, the study identified
several additional issues in need of further examination, including the relative stringency of car and light truck emission standards, the appropriateness of identical versus separate standards for gasoline and diesel vehicles, and the effects of sulfur in gasoline on catalyst efficiency. Section IV of this preamble describes the steps we have taken to follow up on the Tier 2 Study.

In addition, on May 1, 1998, EPA released a staff paper presenting EPA’s understanding of the impact of gasoline
sulfur on emissions from motor vehicles and exploring what gasoline producers and automobile manufacturers could do to reduce sulfur’s impact on emissions. The staff paper noted that gasoline sulfur degrades the effectiveness of catalytic converters and that high sulfur levels in commercial gasoline could affect the ability of future automobiles— especially those designed for very low emissions—to meet more stringent standards in use. It also pointed out that sulfur control will provide additional benefits by lowering emissions from the

current fleet of vehicles.

D. Relationship of Diesel Fuel Sulfur Control to the Tier 2/Gasoline Sulfur Program

In the NPRM, we raised the question of what if any changes to diesel fuel may be needed to enable diesel vehicles to meet the Tier 2 standards or any future heavy-duty diesel engine standards. Specifically, we raised the question of whether diesel sulfur levels

need to be controlled. Since diesel fuel controls of any kind would have an impact on the refinery as a whole, and since in some cases (including potential diesel sulfur limits) could have implications for gasoline sulfur control, we requested comment on this issue in our proposal. We also indicated that we planned to release an Advance Notice of Proposed Rulemaking to solicit more information on this subject.

We published the ANPRM on May 13, 1999 (64 FR 26142). We are in the process of considering all of the comments received in response to the ANPRM and plan to issue a Notice of Proposed Rulemaking (NPRM) in early spring of 2000. We received many comments on the subject of diesel fuel control along with the comments submitted on the proposed Tier 2/ Gasoline Sulfur regulations. We have prepared brief responses to some of these comments in the Response to Comments document, and will deal fully with these comments as part of the forthcoming NPRM on diesel fuel. We are taking no action on diesel fuel as part of today’s action.

II. Tier 2 Determination

Based on the statutory requirements

described above and the evidence provided in the Tier 2 Study and since its release, as described elsewhere in this preamble, EPA has determined that new, more stringent emission standards are indeed needed, technologically feasible, and cost effective.


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9 The Final RIA contains a more detailed analysis,

and Section IV.A. below has further discussion of the technological feasibility of our standards including detailed discussions of the various technology options that we believe manufacturers may use to meet these standards. A. There Is a Substantial Need for
Further Emission Reductions in Order to
Attain and Maintain National Ambient Air Quality Standards

EPA finds that there is a clear air quality need for new emission standards, based on the continuing air quality problems predicted to exist in future years. As the discussion in Section III.B. illustrates, 26 metropolitan areas are each certain or highly likely to
need additional reductions. These areas are distributed across most regions of the U.S., and have a combined population of over 86 million. Section
III.B. also shows that an additional 12 areas each has a moderate to significant probability of needing additional reductions, representing another 25 million people. This provides ample
evidence that further emission
reductions are needed to meet the 1- hour ozone NAAQS.

In addition to these ozone concerns, our analysis of PM 10 monitoring data
and PM 10 projections indicates that 15

PM 10 nonattainment counties violated
the PM 10 NAAQS in recent years, and that 8 of them with a 1996 population of almost 8 million have a high risk of failing to attain and maintain without more emission reductions. Eighteen other counties, with a population of 23 million have a significant risk of failing or are within 10 percent of violating the

PM 10 NAAQS. It is also important to recognize that nonattainment areas remain for other criteria pollutants ( e.g., CO) and that non-criteria pollution ( e.g., air toxics and regional haze) also
contributes to environmental and health

concerns.B. More Stringent Standards for LightDuty Vehicles and Trucks Are Technologically Feasible

We find that emission standards significantly more stringent than current
Tier 1 and National Low Emission Vehicle (NLEV) levels are technologically feasible. This is true both for the LDVs and LDTs specifically covered in section 202(i) and for the medium-duty passenger vehicles also included in today’s final rule. Manufacturers are currently producing NLEV vehicles that meet more stringent
standards than similar Tier 1 models. Our analysis shows that mainly through improvements in engine control software and catalytic converter technology, manufacturers can build and are building durable vehicles and trucks, including heavy light-duty trucks, which have very low emission
levels. 9 Section IV.A. below discusses our feasibility conclusions in more
detail.

Many current production vehicles are already certified at or near the Tier 2 standards. For year 2000 certification (although not yet complete), over 50
vehicle models have emissions at or below Tier 2 levels. In addition, we performed a demonstration program at our EPA laboratory that showed that even large vehicles, which would be expected to face the toughest challenges reaching Tier 2 emission levels, can do so with conventional technology. Others, including the Manufacturers of Emission Controls Association (MECA) and the State of California, have also performed demonstration programs,
with similar results. Manufacturers have
also certified LDVs and LDTs to NMOG and CO levels as much as 80 percent below Tier 1 standards. Furthermore, for passenger vehicles greater than 8500 lbs GVWR, we believe that by using technologies and control strategies similar to what will be used on lighter vehicles, manufacturers will be able to
meet the Tier 2 emission standards.

Thus, we believe that, by the 2004– 2009 time frame, manufacturers will be fully able to comply with the new Tier 2 emission standard levels. In addition,
to facilitate manufacturers’ efforts to meet these new standards, the Tier 2 regulations include a phase-in over several years and a corporate fleet average NO X standard, which will allow manufacturers to optimize the deployment of technology across their product lines with no loss of environmental benefit. Our analysis of the available technology improvements and the very low emission levels already being realized on these vehicles
leads us to find that the standards adopted today are fully feasible for
LDVs and LDTs.

C. More Stringent Standards for LightDuty Vehicles and Trucks Are Needed and Cost Effective Compared to
Available Alternatives

In this action, we also find that more stringent motor vehicle standards are both necessary and cost effective. As discussed above, substantial further
reductions in emissions are needed to help reduce the levels of unhealthy air pollution to which millions of people are being exposed; in particular, we expect that a number of areas will not attain or maintain compliance with the National Ambient Air Quality Standards
for ozone and PM 10 without such reductions. (We describe this further in Section III below and in the RIA.)

Furthermore, mobile sources are important contributors to the air quality problem. As we will explain more fully later in this preamble, in the year 2030, the cars and light trucks that are the subject of today’s final rule are projected to contribute as much as 40 percent of
the total NO X inventory in some cities, and almost 20 percent of nationwide

NO X emissions. This situation would have been considerably worse without the NLEV program created by vehicle manufacturers, EPA, the Northeastern states, and others.

These emission reductions are clearly necessary to meet and maintain the 1- hour ozone NAAQS. We project that
while the emission reductions of this program will lead to substantial progress in meeting and maintaining the NAAQS, many areas will still not come
into attainment even with this magnitude of reductions.

We find that the Tier 2/GasolineSulfur program is a reasonable, costeffective method of providing substantial progress towards attainment and maintenance of the NAAQS, costing about $2000 per ton of NOX plus hydrocarbon emissions reduced. This program will reduce annual NO X emissions by about 2.2 million tons per year in 2020 and 2.8 million tons per year in 2030 after the program is fully implemented. By way of comparison,
when EPA established its 8-hour NAAQS for ozone, we identified several types of emission control programs that were reasonably cost effective. If all of the controls identified in that analysis costing less than $10,000/ton were implemented nationwide, they would produce NO X emission reductions of about 2.9 million tons per year. (That is,
to achieve about the same emission
reductions as the Tier 2/Gasoline Sulfur program, other alternative measures would have a significantly higher cost per ton). These emission reductions are clearly necessary to meet and maintain the one-hour ozone NAAQS. We project
that while the emission reductions of this program will lead to substantial progress in meeting and maintaining the NAAQS, many areas will still not come
into attainment even with this magnitude of reductions.

In addition, the magnitude of
emission reductions that can be achieved by a comprehensive national Tier 2/Gasoline Sulfur program will be difficult to achieve from any other source category. Given the large contribution that light-duty mobile
source emissions make to the national emissions inventory and the range of control programs ozone-affected areas


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10 National Air Quality and Emissions Trend Report, 1997, Air Quality Trends Analysis Group, Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, N.C., December 1998 (available on the World Wide Web at http://www/epa.gov/oar/ aqtrnd97/).

11 U.S. Environmental Protection Agency, Latest Findings on National Air Quality: 1997 Status and
Trends. December 1998. already have in place or would be expected to implement, we believe it will be very difficult, if not impossible, to meet (and maintain) the ozone NAAQS in a cost-effective manner without large emission reductions from LDVs and LDTs. We expect emissions from MDPVs to also play an increasing
role.

Furthermore, we project that the Tier 2/Gasoline Sulfur program will significantly reduce direct and secondary particulate matter coming from LDVs, LDTs, and MDPVs—by about 36,000 tons per year of direct PM alone by 2030; large secondary PM reductions from significantly lower NO X and SO X emissions will add to the overall positive impact on airborne particles. These reductions will be very cost-effective compared to other measures to reduce PM pollution.
Because direct PM emissions from gasoline vehicles are related the presence of sulfur in gasoline, no new emission control devices, beyond what manufacturers are expected to install to
meet the NO X and NMOG standards, will be necessary to provide the reductions expected for these pollutants under the program. The standards will provide valuable insurance against increases in PM emissions from LDVs, LDTs, and MDPVs.

Finally, the Tier 2/Gasoline Sulfur program will significantly reduce CO emissions from LDVs, LDTs, and MDPVs. (See Chapter III of the RIA for an analysis of these reductions.) The technical changes needed to meet the
NMOG standards will also result in CO
reductions sufficient to meet the CO standards. Thus, these CO reductions will be very cost-effective since they will not require any new emission control devices beyond what manufacturers are expected to install to
meet the NO X and NMOG standards.

We conclude, then, that today’s final rule is a major source of ozone precursor, PM, and CO emission reductions when compared to other available options. The discussions of
cost and cost effectiveness later in this preamble and in the RIA explain the
derivation of cost effectiveness estimates and compares them to the cost
effectiveness of other alternatives. That discussion indicates that this program
will have a cost effectiveness comparable to both the Tier 1 and NLEV
standards and will also be cost effective when compared to non-mobile source

programs.
III. Air Quality Need For and Impact Of Today’s Action

In the absence of significant new controls on emission, tens of millions of Americans would continue to be exposed to unhealthy levels of air pollution. Emissions from passenger cars and light trucks are a significant contributor to a number of air pollution problems. Today’s action will significantly reduce emissions from cars and light trucks and hence will significantly reduce the health risks posed by air pollution. This section summarizes the results of the analyses we performed to arrive at our determination that continuing air quality problems are likely to exist, that these air quality problems would be in part due to emissions from cars and light trucks, and that the new standards promulgated by today’s final rule will improve air quality and mitigate other environmental problems.

A. Americans Face Serious Air Quality Problems That Require Further Emission
Reductions

Air quality in the United States continues to improve. Nationally, the 1997 air quality levels were the best on record for all six criteria pollutants. 10 In fact, the 1990s have shown a steady trend of improvement, due to reductions
in emissions from most sources of air pollution, from factories to motor vehicles. Despite great progress in air quality improvement, in 1997 there were still approximately 107 million people nationwide who lived in counties with monitored air quality levels above the primary national air quality standards. 11 There are also people living in counties outside of the air monitoring network where violations of the NAAQS could have also occurred during the year. Moreover, unless there
are reductions in overall emissions beyond those that are scheduled to be achieved by already committed controls, many of these Americans will continue to be exposed to unhealthy air.

Ambient ozone is formed in the lower atmosphere through a complex
interaction of VOC and NO X emissions. Cars and light trucks emit a substantial
fraction of these emissions. Ambient PM is emitted directly from cars and light trucks; it also forms in the atmosphere
from NO X , sulfur oxides (SO X), and VOC, all of which are emitted by motor
vehicles. When ozone exceeds the air quality standards, otherwise healthy people often have reduced lung function and chest pain, and hospital admissions for people with respiratory ailments like asthma increase; for longer exposures, permanent lung damage can occur. Similarly, fine particles can penetrate deep into the lungs. Results of studies suggest a likely causal role of ambient PM in contributing to reported effects, such as: premature mortality, increased hospital admissions, increased respiratory symptoms, and changes in lung tissue. When either ozone or PM air quality problems are present, those hardest hit tend to be children, the elderly, and people who already have health problems.

The health effects of high ozone and PM levels are not the only reason for concern about continuing air pollution. Ozone and PM also harm plants and damage materials. PM reduces visibility and contributes to significant visibility impairment in our national parks and monuments and in many urban areas. In addition, air pollution from motor
vehicles contributes to cancer and other health risks, acidification of lakes and streams, eutrophication of coastal and inland waters, and elevated drinking water nitrate levels. These problems impose a substantial burden on public health, our economy, and our ecosystems.

In recognition of this burden, Congress has passed and subsequently
amended the Clean Air Act. The Clean Air Act requires each state to have an approved State Implementation Plan (SIP) that shows how an area plans to meet its air quality obligations, including achieving and then maintaining attainment of all of the National Ambient Air Quality Standards (NAAQS), such as those for ozone and PM. The Clean Air Act also requires EPA to periodically re-evaluate the NAAQS in light of new scientific
information. Our most recent reevaluation of the ozone and PM NAAQS led us to revise both standards (62 FR 38856, July 18, 1997 and 62 FR 38652, July 18, 1997). These revised standards
reflected additional information that had become available since the previous revision of the ozone and PM standards, respectively.

On May 14, 1999, a panel of the United States Court of Appeals for the
District of Columbia Circuit reviewed
EPA’s revisions to the ozone and PM NAAQS and found, by a 2–1 vote, that
sections 108 and 109 of the Clean Air Act, as interpreted by EPA, represent unconstitutional delegations of Congressional power. American Trucking Ass’n., Inc. et al., v. Environmental Protection Agency, 175 F.3d 1027 (D.C. Cir. 1999). Among other things the Court remanded the record


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for the 8-hour ozone NAAQS and the

PM2.5 NAAQS to EPA. On October 29, 1999, EPA’s petition for rehearing by the three judge panel was denied, with the exception that the panel modified its prior ruling regarding EPA’s authority to implement a revised ozone NAAQS under Part D subpart 2 of Title I. EPA’s petition for rehearing en banc by the full Circuit was also denied, although five of the nine judges considering the petition agreed to rehear the case.

As a result of the Court’s decision, requirements on the States to implement
the new 8-hour ozone standard have been suspended although the standard
itself is still in force and the science behind it has generally not been
contradicted. The court also did not question EPA’s findings regarding the
health effects of PM 10 and PM2.5

. However, due to the uncertainty regarding the status of the new NAAQS, we will rely on the preexisting NAAQS in determining air quality need under section 202(i) of the Act.

Carbon monoxide (CO) can cause
serious health effects for those who suffer from cardiovascular disease, such as angina pectoris. There has been considerable progress in attaining the longstanding NAAQS for carbon monoxide, largely through more stringent standards for CO from motor vehicles. This progress has been made despite large increases in travel by vehicle. In 1997, there were about 9 million people living in three counties
with CO concentrations above the level of the CO NAAQS. In the recent past, this figure has fluctuated up and down. At the present time there are 15 counties
classified as serious CO nonattainment areas, all with a recent history of NAAQS violations. At this time, prospects for these areas attaining by the
serious CO area attainment deadline of December 31, 2000 are uncertain. While violations of the NAAQS have not occurred recently in most of the other
33 counties still classified as nonattainment, even these must demonstrate that they will remain safely below the NAAQS for ten years despite expected growth in vehicle travel and
other sources of CO emissions before they can be reclassified to attainment. Because of the large role of motor vehicles in causing high ambient CO concentrations, where there is reason to
be concerned about CO attainment and maintenance, local areas look to
national emission standards for most of
the solution.

As discussed below, EPA has also finalized regulations that regions and states implement plans for protecting and improving visibility in the 156 mandatory Federal Class I areas as defined in Section 162(a) of the Clean Air Act. These areas are primarily national parks and wilderness areas.

To accomplish the goal of full attainment in all areas according to the schedules for the various NAAQS, and to achieve the goals of the visibility program, the federal government must assist the states by reducing emissions from sources that are not as practical to
control at the state level as at the federal level. Vehicles and fuels move freely among the states, and they are produced by national or global scale industries.
Most individual states are not in a position to regulate these industries effectively and efficiently. The Clean Air Act therefore gives EPA primary authority to regulate emissions from the various types of highway vehicles and
their fuels. Our actions to reduce
emissions from these and other national
sources are a crucial and essential complement to actions by states to
reduce emissions from more localized

sources.

If we were not to adopt new standards to reduce emissions from cars and light trucks, emissions from these vehicles would remain a large portion of the
emissions burden that causes elevated
ozone and continued nonattainment with the ozone NAAQS, which in turn
would affect tens of millions of
Americans. Because the contribution of cars and light trucks to both local emissions and transported pollution would be so great, and the expected emission reduction shortfall in many areas is so large, further reductions from cars and light trucks will be an important element of many attainment strategies, especially for ozone in the
2007 to 2010 time frame. The
contribution of these vehicles to PM exposure and PM nonattainment would also remain significant, and would increase considerably if diesel engines are used in more cars or light trucks. Furthermore, without new standards, steady annual increases in fleet size and miles of travel would outstrip the benefits of current emission controls, and would cause ozone-forming emissions from cars and trucks to grow each year starting about 2013.

The standards being promulgated by today’s actions will reduce emissions of ozone precursors and PM precursors from cars and light trucks greatly. However, even with this decrease, many areas will likely still find it necessary to
obtain additional reductions from other sources in order to fully attain the ozone and PM NAAQS. Their task will be easier and the economic impact on their industries and citizens will be lighter as a result of the standards promulgated by today’s actions. Following implementation of the Regional Ozone Transport Rule, states will have already adopted emission reduction requirements for nearly all large sources
of VOC and NO X for which costeffective control technologies are
known. Those that remain in
nonattainment therefore will have to consider their remaining alternatives. Many of the state and local programs states may consider as alternatives are very costly, and the emissions impact
from each additional emissions source subjected to new emissions controls would be considerably smaller than the emissions impact of the standards being promulgated today. Therefore, the
emission reductions from these standards for gasoline, cars, and light
trucks will ease the need for states to
find first-time reductions from the mostly smaller sources that have not yet been controlled, including area sources that are closely connected with
individual and small business activities.
The emission reductions from the standards being promulgated today will
also reduce the need for states to seek even deeper reductions from large and small sources already subject to
emission controls.

We project that today’s actions will also have important benefits for carbon monoxide, regional visibility, acid rain, and coastal water quality.

For these and other reasons discussed in this document, we have determined that significant emission reductions will still be needed by the middle of the next decade and beyond to achieve and maintain further improvements in air quality in many, geographically dispersed areas. We also believe that a significant portion of these emission reductions will be obtained by reducing emissions from cars and light trucks as a result of today’s actions. We believe that such reductions are necessary (since cars and light trucks are such large contributors to current and projected ozone problems) and reasonable (since these reductions can
be achieved at a reasonable cost compared to other alternative reductions).

The remainder of this section
describes the health and environmental problems that today’s actions will help mitigate and the expected health and
environmental benefits of these actions. Ozone is discussed first, followed by PM, other criteria pollutants, visibility, air toxics, and other environmental impacts. The emission inventories and air quality analyses are explained more fully in the Regulatory Impact Analysis for today’s actions.


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12 Total column ozone, a large percentage of which occurs in the stratosphere and a smaller percentage of which occurs in the troposphere, helps to provide a protective layer against

ultraviolet radiation. B. Ozone

1. Background on Ozone Air Quality

Ground-level ozone is the main harmful ingredient in smog. 12 Ozone is produced by complex chemical reactions when its precursors, VOC and

NO X , react in the presence of sunlight.

Short-term (1–3 hours) and prolonged (6–8 hours) exposures to ambient ozone at levels common in many cities have
been linked to a number of health effects of concerns. For example, increased hospital admissions and emergency room visits for respiratory
causes have been associated with ambient ozone exposures at such levels. Repeated exposures to ozone can make people more susceptible to respiratory infection, result in lung inflammation, and aggravate pre-existing respiratory
diseases such as asthma. Other health effects attributed to ozone exposures include significant decreases in lung function and increased respiratory symptoms such as chest pain and cough. These effects generally occur while individuals are engaged in moderate or heavy exertion.

Children active outdoors during the
summer when ozone levels are at their highest are most at risk of experiencing such effects. Other at-risk groups
include adults who are active outdoors ( e.g., outdoor workers), and individuals with pre-existing respiratory disease
such as asthma and chronic obstructive lung disease. In addition, longer-term exposures to moderate levels of ozone present the possibility of irreversible changes in the lungs which could lead to premature aging of the lungs and/or chronic respiratory illnesses.

Ozone also affects vegetation and ecosystems, leading to reductions in agricultural and commercial forest yields, reduced growth and survivability of tree seedlings, and increased plant susceptibility to disease, pests, and other environmental stresses ( e.g., harsh weather). In long-lived species, these effects may become evident only after several years or even decades, thus having the potential for long-termeffects on forest ecosystems. Groundlevel ozone damage to the foliage of trees and other plants also can decrease
the aesthetic value of ornamental species as well as the natural beauty of our national parks and recreation areas.

Many areas which were classified as
nonattainment when classifications
were made under the 1990 Clean Air Act Amendments have not experienced violations more recently. However, 50 metropolitan areas had ozone design values above the NAAQS in either or
both of the 1995–1997 and the 1996– 1998 monitoring periods. In many urban areas, the downward trend in ozone that prevailed earlier has become less strong or stopped in the last few years, even when adjustments are made for meteorological conditions. We believe that one factor that has worked against ozone improvement in the last few years has been the growing use of light trucks with higher emissions than the cars used formerly. The predictions of future
ozone concentrations used in developing today’s action take account of this growing use of light trucks.

2. Additional Emission Reductions Are
Needed To Attain and Maintain the Ozone NAAQS

a. Summary

We have determined that additional
emission reductions are needed to attain and maintain the 1-hour ozone NAAQS.
This overall conclusion is based on our prediction that 26 metropolitan areas are each certain or highly likely to need additional reductions, and that an
additional 12 areas each have a moderate to significant probability of needing them.

To determine whether additional
reductions are needed in order to attain and maintain the ozone NAAQS, we used ozone modeling to predict what areas would not attain the NAAQS in
the future. We accounted for the emission reductions that have already been achieved, those that will be achieved in the future by actions already underway, and increases in emissions expected from increased use of sources of pollution.

In our May 13, 1999 proposal, we presented information from photochemical modeling we performed to predict what areas would meet the ozone NAAQS in 2007. The year 2007 falls after the expected date of most
emission reductions which states are required to achieve or have otherwise committed to achieve, and near the attainment deadline for many ozone nonattainment areas. We presented
additional information from the same photochemical modeling work in two supplemental notices, on June 30, 1999 (to better explain the basis for our proposal in light of the Court’s ruling on the 8-hour ozone NAAQS), and October 25, 1999 (to explain the implications for our Tier 2/Gasoline Sulfur proposal from our more recent proposal, whichwe expect to make final shortly, to reinstate the 1-hour ozone NAAQS in many areas). In Response to Comments on these Federal Register notices, we
made revisions to our own ozone modeling. We also obtained ozone modeling results from a number of state air planning agencies and from members of the automobile manufacturing industry. We have considered all of this information as part of our determination that the regulations promulgated in this rule are needed and appropriate.

Based on the available ozone modeling and other information, we project that there are 26 metropolitan
areas which will be unable to attain and maintain the NAAQS, in the absence of
additional reductions. These areas had a combined population of over 86 million in 1996, and are distributed across most regions of the U.S. We have concluded that each is certain or very likely to require additional reductions to attain the NAAQS. Taken together and considering their number, size, and geographic distribution, these areas
establish the case that additional
reductions are needed in order to attain
and maintain the 1-hour standard.

In addition, our analysis suggests
there will be other areas that will have problems attaining and maintaining compliance with the one-hour ozone
standard in the future. There are 12 additional metropolitan areas with a total 1996 population of over 25 million people in this category. EPA’s ozone modeling for 2007 predicts exceedances for each of these areas. However, for six of them local recent monitoring information is not indicating
nonattainment. Given how close to nonattainment these areas are, EPA believes it is likely that at least a significant subset of this group of areas will face compliance problems by 2007 or beyond if additional actions to lower
air emissions are not taken. This belief is based on historical experience with areas that will undergo economic and population growth over time and that are in larger regions that are also experiencing growth. The other six areas in this group are nonattainment now, and local modeling shows them reaching attainment by 2005 or 2007. Modeling uncertainties and growth beyond the attainment date make it likely that at least some of these areas will also face compliance problems if
additional actions to lower air emissions
are not taken. This situation further supports our determination that
additional reductions in mobile source
emissions are needed for attainment and

maintenance.

We would like to emphasize that the advantages of the Tier 2/Gasoline Sulfur program will be enjoyed by the whole country. There are important advantages for approximately 30 more metropolitan


### 6708 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

13 As measured by ozone design value. 14 While the use of these emissions estimates was new to our baseline ozone modeling in the latest ozone modeling, they were not new to this rulemaking, having already been used in

calculations of cost-effectiveness in the draft RIA. We therefore were able to consider public comments on these estimates prior to using them in the latest ozone modeling areas, with close to 30 million people residing in them, whose ozone levels are now within 10 percent of violating the 1-hour NAAQS. 13 Most of these areas have been in nonattainment in the past.

We believe the emission reductions from the Tier 2/Gasoline Sulfur program are an important component of an overall EPA-state approach to enable

these areas to continue to maintain clean air given expected growth. EPA believes that the long term ability of the states to continue to meet the NAAQS is extremely important. In the future, EPA will be considering additional approaches for assisting in maintenance of the NAAQS. Also, we believe that the Tier 2/Gasoline Sulfur program has important benefits for other

nonattainment areas which our modeling and local modeling show to be on a path to come into attainment in the next eight years. For these areas, the

extra emission reductions from the program will take some of the uncertainty out of their plan to attain the standard and give them a head start on developing their plan to stay in

attainment.

In every area of the country, the new standards will give transportation planning bodies and industrial development leaders more options

within the area’s overall emissions

constraints. This will allow local and

state officials to better accommodate local needs and growth opportunities.

With these new standards for vehicles and gasoline, unusually adverse weather or strong local economic growth will be less likely to cause ozone levels high enough to trigger the planning requirements of the Clean Air Act. In addition, by reducing emissions and

ozone levels across the nation as a whole, there will be less transport of ozone between areas, reducing the amount of ozone entering downwind areas. This will give the downwind areas a better opportunity to maintain and attain the NAAQS through local

efforts.

All of our determinations presented

here about the need for the Tier 2/ Gasoline Sulfur program take into account the prior NO X reductions we expect from the Regional Ozone Transport Rule. This rule is now in litigation. If the outcome of that litigation reduces the NO X reductions that will be achieved, the need for the Tier 2/Gasoline Sulfur program will be
even greater. b. Ozone Modeling Presented in Our Proposal and Supplemental Notices

The ozone modeling we presented in our proposal and the two supplemental notices was originally conducted as part of our development of the Regional Ozone Transport Rule. The ‘‘revised budget’’ emission control scenario we modeled for the Regional Ozone Transport Rule contained the right set of existing and committed emission controls for it to serve as the starting point for making our determination on
the need for additional emission
reductions. We added a new ‘‘control case’’ to represent the effects of our proposed vehicle and gasoline
standards.

This ozone modeling provided predictions of ozone concentrations in 2007 across the eastern U.S., under certain meteorological conditions.
Predictions of attainment or
nonattainment are based on these predicted ozone concentrations. Two approaches to making attainment predictions have been used or advocated in the past: a rollback approach and an exceedance approach. In the NPRM of May 13, 1999, we presented predictions of attainment and nonattainment using a rollback approach. For the 1-hour standard, we reported that 8 metropolitan areas and two rural counties were predicted to be
in nonattainment in 2007 under the
rollback method. In the first supplemental notice of June 30, 1999 we presented a prediction that 17 areas
would be nonattainment based on the exceedance method, and invited comment on all aspects of the modeling and its interpretation. Our second and last notice on October 27, 1999, presented predictions of violations using the exceedance method for
additional areas which we had previously excluded because the 1-hour standard did not apply to them. This was in anticipation of the reinstatement of the 1-hour standard to these areas, which we proposed on October 25, 1999 and expect to complete very soon. 64 FR
57524. We also announced that we were conducting another round of modeling, described below. See the Response to
Comments document for more
discussion of the rollback and exceedance approaches.

c. Updated and Additional Ozone Modeling

We have updated and expanded our ozone modeling. We updated the ozone modeling so that it is now based on
estimates of vehicle emissions that
reflect the most recent data and our best understanding of several aspects of emissions estimation. 14 We also changed most of the episodes for which we modeled ozone concentrations, with all of our final episode days coming from a single calendar year. By selecting days from within a single year, we responded to a comment that the original episode periods might together contain an atypically high number of days favorable to ozone formation for some parts of the country. The new episodes are also better at representing conditions that lead to high ozone in areas along the Gulf Coast, whose ozone-forming conditions were not well represented in the episodes used for the original modeling.

While we considered these improvements necessary and appropriate in light of comments and other information available to us, the
actual results of the two rounds of modeling with regard to the need for
additional reductions have turned out to be similar. The latest round of modeling provided us ozone predictions for 2007 and 2030 in the eastern U.S., and for
2030 in the western U.S. There are some differences in specific results, where
and when the two models can be directly compared. However, the same
conclusion would be reached from either, namely that there is a broad set of areas with predicted ozone
concentrations in 2007 above 0.124 ppm, in the baseline scenario without
additional emission reductions.

We have compared and supplemented our own ozone modeling with other modeling studies, either submitted to us as comments to this rulemaking, as state implementation plan (SIP) revisions, or brought to our attention through our
consultations with states on SIP revisions that are in development. The ozone modeling in the SIP revisions has the advantage of using emission inventories that are more specific to the area being modeled, and of using meteorological conditions selected specifically for each area. Also, the SIP
revisions included other evidence and analysis, such as analysis of air quality and emissions trends, observation based
models that make use of data on concentrations of ozone precursors, alternative rollback analyses, and information on the responsiveness of the air quality model. For some areas, we decided that the predictions of
attainment or nonattainment from our


### 6709 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

15 EPA’s modeling presumed that cars and light

trucks will continue to meet the emission levels of the National Low Emissions Vehicle (NLEV) program after model year 2003, even though the program will end in model year 2003 or shortly thereafter. Had our modeling not included such levels in its inventory assumptions, trends for

ozone concentrations would have shown earlier

increases in ozone concentrations.

16 The date of the predicted violation was 2007 for most areas, 2010 in the case of Los Angeles, CA, and 2030 in the case of Portland-Salem, OR. 17 With regard to eventual final action on the 1- hour attainment demonstration for Washington, DC,

the issue of the continuation of the NLEV standards is mooted by the promulgation of the Tier 2/ Gasoline Sulfur program. A portion of the emissionreductions from this program will replace the post2003 model year NLEV reductions assumed in the

SIP. modeling were less reliable than
conclusions that could be drawn from this additional evidence and analysis. For example, in some areas our episodes did not capture the meteorological conditions that have caused high ozone, while local modeling did so.

d. Results and Conclusions

As discussed in detail below, it is
clear that the NO X and VOC reductions to be achieved through the Tier 2/ Gasoline Sulfur program are needed to attain and maintain compliance with the 1 hour ozone NAAQS. Although the general pattern observed in our modeling indicates improvements in the near term, growth in overall emissions will lead to worsening of air quality over the long term.

Based on our ozone modeling, we have analyzed ozone predictions for 52 metropolitan areas for 1996, 2007, and 2030. In addition, we reviewed ozone attainment modeling and other evidence covering 15 of these areas, from SIP submittals or from modeling underway to support SIP revisions. This local modeling addressed only the current or requested attainment date in each area.
We then made attainment and nonattainment predictions from this
information.

The general pattern we observed with the baseline scenario, i.e., without new emission reductions, is a broad
reduction between 1996 and 2007 in the geographic extent of ozone concentrations above the NAAQS, and in the frequency and severity of
exceedances. This is consistent with the national emissions inventory trend between these two years. At the same time, we also found that peak ozone concentrations and the frequency of exceedances in 2030 were generally somewhat higher than in 2007 for most areas analyzed. This too is consistent with our analysis of emission inventory trends, which shows that the total NOX inventory from all sources will decline from 2007 to about 2015 and then begin to increase due to growth in the activity of emission sources. In 2030, our analysis predicts that NO X emissions
from all sources will be about one percent higher than in 2007. While we
did not model ozone concentrations for years between 2007 and 2030, we expect that they would track the national emissions trend by showing a period of improvement after 2007 and then deterioration, although individual areas will vary due to local source mix and growth rates. 15 Within this general pattern of ozone attainment changes between 1996 and 2030, we have determined that 26 metropolitan areas are certain or highly likely to need additional reductions to
attain and maintain the 1-hour ozone NAAQS. These 26 areas are those that
have current violations of the 1-hour ozone NAAQS and are predicted by the best ozone modeling we have available
to still be in violation without a new federal vehicle program in 2007. 16 Based on the general trends described above, without further emissions reductions many of these areas may also have violations continuously throughout the period from 2007 to 2030, while others may briefly attain
and then return to nonattainment on or before 2030. These 26 metropolitan areas are listed in Table III.B–1, along with their 1996 population which totals
over 86 million. The sizes of these areas and their geographical distribution strongly support an overall need for
additional reductions in order to attain and maintain under section 202(i). Because ozone concentration patterns causing violations of the 1-hour NAAQS are well established to endanger public health or welfare, this determination also supports our actions today under the general authority of sections 202(a)(1), 202(a)(3), and 202(b).

As indicated above, in reaching this conclusion about these 26 areas, we examined local ozone modeling in SIP submittals. These local analyses are
considered to be more extensive than our own modeling for estimating whether there would be NAAQS
nonattainment without further emission reductions, when interpreted by a weight of evidence method which meets our guidance for such modeling. One of
the areas which submitted a SIP revision was a special case. We have recently proposed to approve the 1-hour
ozone attainment demonstration for the nonattainment area of Washington, D.C. (but not Baltimore). We have
nevertheless included this area on the list of 26 that are certain or highly likely to require further reductions to attain and maintain, because its SIP
attainment demonstration assumed
emission reductions from vehicles meeting the National Low Emissions Vehicle (NLEV) standards. However, by its own terms, the NLEV standards would not extend beyond the 2003 model year if we did not promulgate Tier 2 vehicle standards at least as stringent as the NLEV standards. See 40 CFR 86.1701–99(c). Thus, the emission reductions relied upon from 2004 and later model year NLEV
vehicles are themselves ‘‘further reductions’’ for the purposes of CAA section 202(i). 17 The local modeling indicating attainment with these reductions is therefore strong evidence that further reductions are needed past 2003, beyond those provided by the Tier 1 program. Based on this, and on the fact that our own ozone modeling showed the Washington, DC area to violate the NAAQS in 2007 even with full NLEV emission reductions, we have
concluded that it should be included with areas that do require further
reductions to attain and maintain the 1- hour ozone NAAQS.

The 1-hour ozone NAAQS presently does not apply in 12 of the 26 areas listed in Table III.B–1, but we have proposed to re-instate it and expect to complete that action shortly. These
areas are indicated in the table. Our
decision to include these areas on this list is based on the contingency that we
will re-instate the 1-hour standard in these areas. However, even if we considered only the 14 areas where the 1-hour standard applies as of the signature date of this notice, we have
concluded that our determination
would be the same.



### TABLE 

### III.B–1.—TWENTY

### -S IX 

### M ETRO



### POLITAN 

### A REAS 

### W HICH 

### A RE 

### C ER



### TAIN OR 

### H IGHLY 

### L IKELY 

### TO 

### R EQUIRE 

### A DDITIONAL 

### E MISSION 

### R EDUCTIONS

IN 

### O RDER 

### TO 

### ATTAIN AND 

### M AINTAIN

THE 

### 1-H OUR 

### OZONE 

### NAAQS

Metropolitan area 1996 Population (millions)

Atlanta, GA MSA ...................... 3.5
Barnstable-Yarmouth, MA

MSA a .................................... 0.2 Baton Rouge, LA MSA ............. 0.6 Beaumont-Port Arthur, TX MSA 0.4 Birmingham, AL MSA ............... 0.9 Boston-Worcester-Lawrence,

MA–NH–ME–CT CMSA a ...... 5.6 Charlotte-Gastonia-Rock Hill,

NC–SC MSA a ....................... 1.3


### 6710 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

18 The SIP revisions for Chicago and Milwaukee

demonstrated that these two areas as well as Benton Harbor and Grand Rapids areas in Michigan (which are maintenance areas but have experienced ozone NAAQS violations recently) would not experience NAAQS violations in 2007, with a strategy that relied only on Tier 1 vehicle emission standards. We have also recently proposed to approve the 1-

hour attainment demonstration for Greater Connecticut, covering the Hartford and New London areas, which assumed full NLEV emission reductions. However, Connecticut is committed in its SIP to adopt California vehicle standards if NLEV does end with the 2003 model year if a more stringent federal program is not promulgated. The California standards are more stringent than NLEV.

The case of one additional area whose attainment demonstration we recently proposed to approve, Western Massachusetts (Springfield), should be explained here to avoid possible confusion. Our own ozone modeling predicted that Springfield would attain the NAAQS in 2007. Massachusetts has adopted the California vehicle emission standards, so there is no issue of the continuation

of the NLEV standards. 

### TABLE 

### III.B–1.—TWENTY

### -S IX 

### M ETRO



### POLITAN 

### A REAS 

### W HICH 

### A RE 

### C ER



### TAIN OR 

### H IGHLY 

### L IKELY 

### TO 

### R EQUIRE 

### A DDITIONAL 

### E MISSION 

### R EDUCTIONS

IN 

### O RDER 

### TO 

### ATTAIN AND 

### M AINTAIN

THE 

### 1-H OUR 

### OZONE 

### NAAQS—Continued

Metropolitan area 1996 Population (millions)

Cincinnati-Hamilton, OH–KY–IN

CMSA .................................... 1.9 Dallas-Fort Worth, TX CMSA ... 4.6 Houma, LA MSA a .................... 0.2 Houston-Galveston-Brazoria,

TX CMSA .............................. 4.3 Huntington-Ashland, WV–KY–

OH MSA a .............................. 0.3 Indianapolis, IN MSA a .............. 1.5 Los Angeles-Riverside-San

Bernardino CA CMSA ........... 15.5 Louisville, KY–IN MSA ............. 1.0 Macon, GA MSA a .................... 0.3 Memphis, TN–AR–MS MSA a ... 1.1 Nashville, TN MSA a ................. 1.1
New York-Northern New Jersey-Long Island, NY–NJ–
CT–PA CMSA ....................... 19.9Philadelphia-Wilmington-Atlantic City, PA–NJ–DE–MD
CMSA .................................... 6.0 Pittsburgh, PA MSA .................. 2.4 Portland-Salem, OR–WA

CMSA a .................................. 2.1 Providence-Fall River-Warwick,

RI–MA MSA a ........................ 1.1 Richmond-Petersburg, VA

MSA a .................................... 0.9 St. Louis, MO–IL MSA .............. 2.5 Washington-Baltimore, DC–

MD–VA–WV CMSA .............. 7.2 Total Population ............. 86.3

Notes:

a The 1-hour ozone NAAQS does not currently apply, but we have proposed and expect to re-instate it shortly.

There are 12 additional metropolitan areas, with another 25.3 million people in 1996, for which the available ozone modeling suggests significant risk of failing to attain and maintain the 1-hour ozone NAAQS without additional
emission reductions. Table III.B–2 lists the areas we put in this second category. Our own ozone modeling predicted
these 12 areas to need further reductions
to avoid violations in 2007. For six of these areas, recent air quality monitoring data indicate violation, but we have reviewed local ozone modeling and other evidence indicating

attainment in 2007. 18 Based on this evidence, we have kept these areas separate from the previous set of 26
areas which we consider certain or highly likely to need additional reductions. However, we still consider there to be a significant risk of failure to
attain and maintain in these six areas because this local modeling has inherent uncertainties, as all ozone modeling does. Moreover, the local modeling did not examine the period
after initial attainment.

For the other six of the 12 areas, the air quality monitoring data shows
current attainment but with less than a 10 percent margin below the NAAQS. This suggests these areas may remain without violations for some time, but we
believe there is still a moderate risk of future violation of the NAAQS because meteorological conditions may be more
severe in the future.

It is highly likely that at least some of these 12 areas will violate the NAAQS without additional reductions, and it is a distinct possibility that many of them
will do so. We consider the situation in these areas to support our determination that, overall, additional reductions are
needed for attainment and maintenance. However, we reiterate that our predictions for the 26 areas listed in Table III.B–1, and even our predictions for only the 14 of those 26 for which the 1-hour standard now applies, are a
sufficient basis for our determination of
an overall need for additional reductions and for our actions today.



### TABLE 

### III.B–2.—TWELVE 

### M ETROPOLI



### TAN 

### A REAS 

### W ITH 

### M ODERATE TO 

### S IGNIFICANT 

### R ISK OF 

### FAILING 

### TO 

### ATTAIN AND 

### M AINTAIN THE 

### 1-H OUR 

### OZONE 

### NAAQS W ITHOUT 

### A DDI



### TIONAL 

### E MISSION 

### R EDUCTIONS

Metropolitan area 1996 Population (millions)

Benton Harbor, MI MSA a ......... 0.2 Biloxi-Gulfport-Pascagoula, MS

MSA a .................................... 0.3 

### TABLE 

### III.B–2.—TWELVE 

### M ETROPOLI



### TAN 

### A REAS 

### W ITH 

### M ODERATE TO 

### S IGNIFICANT 

### R ISK OF 

### FAILING 

### TO 

### ATTAIN AND 

### M AINTAIN THE 

### 1-H OUR 

### OZONE 

### NAAQS W ITHOUT 

### A DDI



### TIONAL 

### E MISSION 

### R EDUCTIONS



### — Continued

Metropolitan area 1996 Population (millions)

Chicago-Gary-Kenosha, IL–IN–

WI CMSA .............................. 8.6 Cleveland-Akron, OH CMSA a .. 2.9 Detroit-Ann Arbor-Flint, MI

CMSA a .................................. 5.3Grand Rapids-Muskegon-Holland, MI MSA a ...................... 1.0 Hartford, CT MSA ..................... 1.1 Milwaukee-Racine, WI CMSA .. 1.6 New London-Norwich, CT–RI

MSA a .................................... 1.3 New Orleans, LA MSA a ........... 0.3 Pensacola, FL MSA a ............... 0.4 Tampa, FL MSA a ..................... 2.2

Total Population ............. 25.3

Notes:

a The 1-hour ozone NAAQS does not currently apply, but we have proposed and expect to re-instate it shortly.

e. Issues and Comments Addressed

We received detailed comments from the automobile industry related to ozone modeling and the need for additional
emission reductions in order to attain and maintain. These were of three types.

Accuracy of modeling ozone

concentrations.—The automobile industry commenters pointed out that in the modeling presented with our proposal, the ozone model and exceedance predicted violations of the NAAQS in 1995 in areas where monitoring data indicated no violations. They cited these cases as examples of model inaccuracy. We have made improvements to our emissions estimates, our episodes, and other aspects of the modeling system. These changes have improved the accuracy of the predicted ozone concentrations. Also, as stated above, our list of 26 areas that support our finding that additional
reductions are needed does not include any areas where recent monitoring data
shows no violations. The final RIA addresses issues of model accuracy in more depth.

As explained in the final RIA, our very latest estimates of car and light
truck emissions without the benefits of our new standards are actually somewhat higher than the estimates
used in the final round of ozone modeling, because the most recent data
indicate even more serious adverse
emissions effects from sulfur in


### 6711 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

19 We did not include the Los Angeles-RiversideSan Bernardino area in this analysis, since it was not covered by our 2007 modeling, but we do believe it is rightly part of the basis for a

determination on the need for additional

reductions. 20 As explained in the final RIA, our very lastest estimates of car and light truck emissions without the benefits of our new standards are actually somewhat higher than the estimates used in the final round of ozone modeling, because more recent
data indicate even more serious adverse emissions effects from sulfur in gasoline. Thus, we think our predictions of ozone nonattainment may be

conservative. gasoline. Thus, we think our predictions of ozone nonattainment using emission estimates prepared before this most recent data on sulfur was considered, may be conservative. This topic is
discussed in more detail in section

III.B.3.

Prediction of attainment/

nonattainment.—For most areas, we predicted 2007 or 2030 attainment or
nonattainment based on the exceedance
method. The exceedance method predicts an area to be in attainment only if there are no predicted exceedances of the NAAQS during any episode day. However, for the areas for which we
have received 1-hour attainment demonstrations in SIP revisions, our predictions were based on a larger and
more robust set of data. When a state’s modeling shows an exceedance that
would otherwise indicate nonattainment, we allow the state to submit a variety of other evidence and analysis, such as locality specific meteorological conditions, analysis of air quality and emissions trends,
observational based models that make
use of data on concentrations of ozone precursors, a rollback analysis, and information on the responsiveness of the air quality model. We then make a weight-of-evidence determination of
attainment or nonattainment based on
consideration of all this local evidence. We did this in forming the set of 26 areas we consider certain or highly likely to need additional reductions to attain or maintain, in some cases concluding that attainment was
demonstrated and in others that it was

not.

The auto industry commenters
recommended the use of rollback as the single method for making attainment and nonattainment predictions from predicted ozone concentrations. They
stated that the rollback method would
be more consistent than the exceedance method with the NAAQS’s allowance of three exceedances in a three year period. They also believed that the rollback method would compensate for what they considered to be model over predictions of ozone concentrations. We
believe that the rollback method is not appropriate for use as the sole, or even a primary, test of 1-hour ozone
attainment or nonattainment. A rollback analysis may overlook violations that occur away from ozone monitors, and it may inappropriately project the effect of a recent period of favorable weather into the prediction of future attainment. In determining the attainment and maintenance prospects of numerous areas, as here, it is not possible to
assemble and consider the full set of local evidence that should accompany any consideration of a rollback analysis. In such a situation, we believe that the exceedance method is the appropriate choice. A fuller explanation of our reasons for considering the exceedance method more appropriate than rollback is given in our Response to Comments
document.

We have not completely excluded the rollback approach from the determinations in this rulemaking. We
have considered it for those areas for which we had enough information to allow us to consider it in its proper context, i.e., for those areas covered by
recent 1-hour SIP submissions. Of these areas, we concluded that some will not
attain without additional reductions and
some will.

While we disagree with the use of the rollback method, we have conducted a hypothetical analysis of 2007 attainment in all areas based only on our own ozone modeling, applying the rollback method recommended by the
commenters. We calculated in this analysis that 15 metropolitan areas and three other counties with nearly 56 million in population in 1996 would violate the NAAQS in 2007. Moreover, these 15 metro areas are geographically spread out 19 . We believe that this result using the rollback method does not fully capture the likely nonattainment that
would exist in 2007 in the absence of
additional emission reductions. However, even if we were to consider the use of rollback valid, we consider this set of areas to also be an adequate basis for making the same
determinations we have made based on the more appropriate exceedance-based analysis. The details of our hypothetical analysis using the rollback method are given in the final RIA and the technical support document for our ozone modeling analyses.

Ozone modeling and predictions.

— Members of the automobile manufacturing industry submitted two modeling studies: (1) a repetition of our first round of modeling of the 37-state
eastern U.S. domain but with their recommendations regarding estimates of
motor vehicle emissions in 2007 and
with the rollback method used to predict 2007 nonattainment, and (2) finer grid modeling for three smaller domains, also with their recommended
estimates of emissions and with nonattainment predicted using a rollback method. Both modeling efforts showed less widespread nonattainment than we have determined and described here. Taken together, these studies predicted 2007 violations by the
rollback method in or downwind of New York City, Chicago, Milwaukee, western Michigan, Baton-Rouge, and

Houston.

The main difference between the automobile industry’s ozone modeling
and ours is in the emission estimates.
We have reviewed the emissions estimates used in the industry studies. We concluded that the industry’s emissions estimates employ inappropriate analytical steps in the calculation. Among the problems are that the adjustments for the benefits of inspection and maintenance programs
were not consistent with the base estimate of in-use emissions, and the sales trend towards light trucks and SUVs was not properly captured. Also, as stated, we disagree with the use of the rollback approach as the sole test of attainment. As a consequence, we conclude that the industry’s ozone modeling is not an appropriate basis for making predictions of future attainment
or nonattainment. The final RIA explains in detail how we have
addressed these and other emissions modeling issues in a manner which is more technically consistent and

correct, 20 and how we have considered the results from rollback analyses but only as part of broad weight-of-evidence
determinations for areas for which thiswas possible at this time. Our point-bypoint review is given in our Response to
Comments document.

The material on ozone modeling submitted by the commenters, having been prepared by the rollback method, was difficult to re-interpret according to our preferred exceedance method. However, it appears that if this modeling were interpreted by the exceedance method, it would indicate
2007 nonattainment in Baltimore and Washington, D.C. in addition to New York City, Chicago, Milwaukee, western Michigan, Baton-Rouge, and Houston. Overall, we conclude that the material submitted by the automobile industry
does not contradict the facts we have
used to make our determinations or the actions we are taking today.

f. 8-Hour Ozone

The predictions of ozone concentrations from the ozone modeling


### 6712 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

21 Emission Trend Report, 1997.

22 The auto manufacturer and northeastern state commitments to the NLEV program are scheduled

to end in 2004 without further EPA action on Tier 2 standards, although continued voluntary compliance by automobile manufacturers and the affected states is a possibility. Our analysis of emission trends and the emission benefits expected from today’s action assumes for the base scenario a continuation of the NLEV program past 2004. If the NLEV program does not continue beyond 2004, the reductions resulting from Tier 2 would be larger

than what is shown here. It also includes all other control measures assumed to be implemented in local areas, such as reformulated gasoline in all required and opt-in areas and enhanced I/M where required.

23 Also, if the NLEV program ends in model year 2004 or shortly thereafter, as scheduled, this trend would reverse more quickly in all areas. can be used to make predictions of
attainment or nonattainment with the 8- hour ozone NAAQS. In our draft RIA, we estimated that 28 metropolitan areas
and 4 rural counties with a combined population of 80 million people would violate the 8-hour ozone NAAQS in
2007 without additional emission
reductions. Commenters noted
differences between exact rollback procedure we had used in this projection and the steps specified in recent draft guidance we have issued on 8-hour ozone modeling. We agree with the commenters that the steps specified in our guidance are the correct ones to use. However, since we are not basing our promulgation of the Tier 2/Gasoline Sulfur Program on the 8-hour ozone NAAQS, we have not made any new predictions of 8-hour ozone
nonattainment areas in 2007. Based on our findings in previous analyses of this sort, however, we believe that in the
absence of the Tier 2/Gasoline Sulfur program there would be 8-hour
nonattainment areas that are not also
areas which we have concluded are certain or highly likely to violate the 1- hour NAAQS. If we considered it appropriate to proceed with implementation of the 8-hour standard, these areas would support our
determination on the need for emission reductions, and the appropriateness and necessity of the vehicle and gasoline standards we are establishing.

3. Cars and Light-duty Trucks Are a Big
Part of the NO X and VOC Emissions, and Today’s Action Will Reduce This Contribution Substantially

Emissions of VOCs and NO X come from a variety of sources, both natural and man-made. Natural sources, including emissions that have been traced to vegetation, account for a substantial portion of total VOC
emissions in rural areas. The remainder
of this section focuses on the
contribution of motor vehicles to
emissions from human sources. Manmade VOCs are released as byproducts of incomplete combustion as well as evaporation of solvents and fuels. For gasoline-fueled cars and light trucks, approximately half of the VOC
emissions come from the vehicle
exhaust and half come from the evaporation of gasoline from the fuel system. NO X emissions are dominated by man-made sources, most notably high-temperature combustion processes such as those occurring in automobiles and power plants. Emissions from cars and light trucks are currently, and will remain, a major part of nationwide VOC
and NO X emissions. In 1996, cars and light trucks comprised 25 percent of the VOC emissions and 21 percent of the

NO X emissions from human sources in
the U.S. 21 The contribution in metropolitan areas was generally larger.

We have made significant improvements in the analysis used to estimate the emission inventory impacts of this action, including improving the emission factor modeling, using more detailed local modeling input, and using a more conservative (lower) estimate of VMT growth. These changes are detailed in the Regulatory Impact Analysis for this rule. The following discussion is based on this improved analysis.

In addition to the improvements which are incorporated in this analysis, we also made further improvements in the emission factor modeling after analyzing comments which we did not have time to incorporate into the detailed inventory analysis described here. The most notable change is related
to data which indicates that NOX and

NMOG emissions are even more sensitive to gasoline sulfur than previously thought. This change and
others are described in detail in the Response to Comments. Our early analysis of these changes indicates that incorporating them into this analysis would provide further support for this action because these changes result in
both increases in the baseline emissions
without Tier 2 and in the reductions
that would result from Tier 2. For example, in the detailed inventory analysis we report below, we project
nationwide Tier 2/Gasoline Sulfur
control NO X reductions from cars and light trucks of 856,471 tons per year in 2007. Using the version of the emission factor model that incorporates these additional changes increases the
estimated Tier 2 reductions to approximately 1.0 million tons per year in 2007 (estimated baseline emissions
without Tier 2 increase from 3.1 million tons per year in 2007 to approximately 3.7 million tons per year using the
version of the emission factor model that incorporates these additional changes). Therefore, the estimates of the inventory reductions given here (and
used as the basis for the ozone air quality analysis) are clearly

conservative.

Motor vehicle emission controls have led to significant improvements in emissions released to the air (the ‘‘emission inventory’’) and will
continue to do so in the near term 22 . In the current analysis, we continue to find
that total emissions from the car and light truck fleet would continue to decline for a period, even if we were not establishing the Tier 2/Gasoline Sulfur program. This decline would result from
the introduction of cleaner reformulated gasoline in 2000, the introduction of
National Low Emission Vehicles (NLEVs) and vehicles complying with the Enhanced Evaporative Test Procedure and Supplemental Federal Test Procedures, and the continuing removal of older, higher-emitting
vehicles from the in-use vehicle fleet. On a per mile basis, VOC and NOX emissions from cars and light trucks
combined would have continued to decline well beyond 2015, reflecting the continuing effect of fleet turnover under existing emission control programs. However, projected increases in vehicle miles traveled (VMT) will cause total
emissions from these vehicles to
increase. With this increase in travel and without additional controls, we project that combined NO X and VOC emissions for cars and light trucks
without the Tier 2/Gasoline Sulfur program would increase starting in 2013 and 2016, respectively, so that by 2030 they would return to levels above or nearly the same as they will be in 2000. In cities experiencing rapid growth, such as Charlotte, North Carolina, the
near-term trend towards lower
emissions tends to reverse sooner. 23 With additional improvements in the modeling done in Response to Comments, we now estimate that
without the Tier 2/Gasoline Sulfur program, there will be a constant
increase in these emission over time.

Figure III–1 illustrates this expected trend in car and light truck NOX emissions in the absence of today’s action. The figure also allows the contribution of cars to be distinguished from that of light trucks. The figure clearly shows the impact of steady growth in light truck sales and travel on overall light-duty NO X emissions; the decrease in overall light-duty emission levels is due solely to reductions in LDV emissions. In 2000, we project that


### 6713 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

24 Today’s action for both vehicles and fuels will apply in 49 states and the U.S. territories, excluding only California. There will also be emissions
reductions in California from vehicles that relocate or visit from other states. However, much of the emissions inventory analysis for this action was made for a 47-state region which excludes California, Alasks, and Hawaii. The latter two states were not included in the scope of ozone, PM and economic benefits modeling. trucks will produce about 50 percent of combined car and light truck NOX emissions. We project that truck emissions would actually increase after 2000, and over the next 30 years, trucks would grow to dominate light-duty NOX emissions. By 2010, we project trucks would make up two-thirds of light-duty NO X emissions; by 2020, nearly threequarters of all light-duty NO X emissions would be produced by trucks.

BILLING CODE 6560–50–P

BILLING CODE 6560–50–C

Today’s action will significantly decrease NO X and VOC emissions from cars and light trucks, and will delay the date by which NO X and VOC emissions will begin to increase due to continued VMT growth. With Tier 2/Gasoline Sulfur control, light-duty vehicle NO X and VOC emissions are projected to continue their downward trend past 2020. Table III.B–3 shows the annual tons of NO X that we project will be reduced by today’s action. 24 These projections include the benefits of low sulfur fuel and the introduction of Tier 2 car and light truck standards.



### TABLE 

### III.B–3.—NOX 

### E MISSIONS 

### F ROM 

### CARS AND 

### L IGHT 

### T RUCKS AS 

### P ERCENT OF 

### TOTAL 

### E MISSIONS



### , AND 

### R EDUCTIONS 

### D UE TO 

### T IER 

### 2/G ASOLINE 

### S ULFUR 

### C ONTROL 

### (TONS PER YEAR

### ) a

Year Light-duty tons— without tier 2 Light-duty percent of total
without tier 2 Light-duty tons reduced by tier
2 c, c

2007 ........................................................................................................................... .................. 3,095,698 16 856,471

2010 ........................................................................................................................... .................. 2,962,093 16 1,235,882

2015 ........................................................................................................................... .................. 2,968,707 17 1,816,767

2020 ........................................................................................................................... .................. 3,160,155 17 2,220,210


### 6714 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

25 California Air Resources Board, Executive Order G–99–037, May 20, 1999, Attachment A, 6– 7, 10. These NO X reductions represent a small fraction of the emission reductions needed in the South Coast to attain the NAAQS. 

### TABLE 

### III.B–3.—NOX 

### E MISSIONS 

### F ROM 

### CARS AND 

### L IGHT 

### T RUCKS AS 

### P ERCENT OF 

### TOTAL 

### E MISSIONS



### , AND 

### R EDUCTIONS 

### D UE TO 

### T IER 

### 2/G ASOLINE 

### S ULFUR 

### C ONTROL 

### (TONS PER YEAR

### ) a

### —Continued

Year Light-duty tons— without tier 2 Light-duty percent of total
without tier 2 Light-duty tons reduced by tier
2 b, c

2030 ........................................................................................................................... .................. 3,704,747 19 2,795,551

Notes:

a Estimates exclude California, Alaska, and Hawaii, although reductions will occur in all three.

b Does not include emission reductions from heavy-duty gasoline vehicles.

c These numbers represent a conservative estimate of the benefits of the Tier 2/Sulfur program. Based on the updated emission factor model developed in response to comments, the program will result in significantly larger benefits. For example, our new model projects NOX reductions of 1,100,000 tons in 2007.

The lower sulfur levels in today’s action will produce large emission reductions on pre-Tier 2 vehicles as soon as low-sulfur gasoline is introduced, in addition to enabling Tier
2 vehicles to achieve lower emission levels. Among the pre-Tier 2 vehicles, the largest per vehicle emission reductions from lower sulfur in gasoline
will be achieved from vehicles which
automobile manufacturers will have sold under the voluntary National Low Emission Vehicle program. These vehicles are capable of substantially lower emissions when operated on low sulfur fuel. Older technology vehicles experience a smaller but significant
effect.

In 2007, when all gasoline will meet the new sulfur limit and when large
numbers of 2004 and newer vehicles meeting these standards will be in use,
the combined NO X emission reduction
from vehicles and fuels will be over 850,000 tons per year. After 2007,
emissions will be reduced further as the
fleet turns over to Tier 2 vehicles operating on low sulfur fuel. By 2020,

NO X emissions will be reduced by 70%
from the levels that would occur without today’s action. This reduction equals the NO X emissions from over 164 million pre-Tier 2 cars and light trucks. This reduction represents a 12 percent
reduction in NO X emissions from all
manmade sources.

VOC emissions will also be reduced by today’s action, with reductions increasing as the fleet turns over. We estimate that the reductions as a percent of emissions from cars and light trucks will be 7 percent in 2007 and grow to 17 percent in 2020.

As discussed earlier, in California,
smaller but still substantial reductions
in both NO X and VOC will be achieved because vehicles visiting and relocating to California will be designed to meet these standards. Also, vehicles from California visiting other states will not be exposed to high sulfur fuel.
California Air Resources Board staff
have estimated that Tier 2/Sulfur will
reduce NO X emissions in the South Coast Air Quality Management District by approximately 4 tons per day in

2007. 25 CARB staff plan to incorporate
these reductions in their revised attainment plan for this district, which includes most of the Los Angeles-Long Beach region.

These estimates of emission reductions reflect a mixture of urban, suburban, and rural areas. However, cars and light trucks generally make up a larger fraction of the emission inventory for urban and suburban areas, where human population and personal

vehicle travel is more concentrated than

emissions from other sources such as heavy-duty highway vehicles, power plants, and industrial boilers. We have

estimated emission inventories for three cities using the same methods as were used to project the nationwide inventories, and we present the results

for 2007 below in Table III.B–4.

These results confirm that light-duty vehicles make up a greater share of the

NO X emission inventories in urban areas than they do in the nationwide inventory. While these vehicles’ share of

national NO X emissions in 2007 is about 16 percent, it is estimated to be about 34 percent in the Atlanta area. There is also a range in VOC contributions, with Atlanta again being the area with the largest car and light truck contribution at 17 percent. In metropolitan areas with high car and light truck contributions, today’s action will represent a larger step towards attainment since it will have a larger effect on total emissions.



### TABLE 

### III.B–4—Proportion of the Total Urban Area NOX 

### and VOC Inventory in 2007 Attributable to Light-Duty

Vehicles a

Region NOX (percent) VOC (percent)

Nationwide ..................................................................................................................... .................................................. 16 13

New York urban area ............................................................................................................ .......................................... 18 6

Atlanta urban area ............................................................................................................. .............................................. 34 17
Charlotte urban area ........................................................................................................... ............................................. 24 15

Notes:

a The estimates reflect continuation of NLEV beyond 2004.

Another useful perspective from which to view the magnitude of the emission reductions from today’s proposal is in terms of the additional

emission reductions from all human sources that areas will need to attain the

1-hour ozone standard. For this analysis, we reviewed our proposals for

action on the 1-hour attainment demonstrations submitted by the states. With these proposals, EPA identified

estimates of additional emission reductions (measures in addition to those submitted by the state in their plans) necessary for attainment for some


### 6715 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

26 EPA assessment of air quality changes for 2007

and 2030 focused on 37 states in the East because

these states cover most of the areas with 1-hour nonattainment problems. of the areas. These estimates of
additional emission reductions are
documented in the individual Federal Register Notices. Using these estimates
and the estimates of Tier 2 reductions developed for today’s action, we have determined what portion of these
additional emission reductions would be accounted for by today’s action. These estimates are reported in Table III.B–5, which shows the contribution of
Tier 2/Sulfur NO X reductions to the additional emission reduction necessary for attainment for three metropolitan areas. For example, for the New York nonattainment area, 89% of the
additional NO X emission reductions needed for attainment are provided for with today’s action. This leaves 11% of
the additional NO X emission reductions to be addressed by the State through
other local sources.

EPA and the States already have significant efforts underway to lower ozone precursor emissions through national regulations and State Implementation Plans. Table III.B–5
shows the contribution of Tier 2 to the substantial State-led efforts to provide attainment with the ozone NAAQS. Since the Tier 2 program has evolved in the past year after much of the States’ efforts were completed, many of the
States were unable to estimate the
benefits of Tier 2 in their areas. EPA’s proposal actions on these SIPs for the ozone NAAQS addresses the need for Tier 2 in many areas. More specifically, Tier 2 is being used to help States identify additional measures, in addition to those in their plans, necessary for attainment.

These estimates are subject to change
as the states review and comment on our proposed action on the SIPs. These figures show that today’s proposal would make a very substantial
contribution to these cities’ attainment programs, but that there will still be a
need for additional reductions from
other sources. The emission reductions from today’s proposal would clearly not
exceed the reductions needed from an air quality perspective for these areas.



### TABLE 

### III.B–5.—C ONTRIBUTION OF 

### T IER 

### 2/S ULFUR 

### NOX 

### R EDUCTIONS TO 

### OZONE 

### ATTAINMENT 

### E FFORTS OF 

### S ELECTED 

### N ONATTAINMENT 

### A REAS

Nonattainment area (attainment date) Percent of additional NOX reductions necessary for
attainment

From tier 2 Needed after tier 2

Baltimore (2005) ............................................................................................................... ............................................... 100 0 New York (2007) ................................................................................................................ .............................................. 89 11 Philadelphia (2005) ............................................................................................................ .............................................. 87 13

4. Ozone Reductions Expected From
This Rule

The large reductions in emissions of ozone precursors from today’s standards will be very beneficial to federal and
state efforts to lower ozone levels and bring about attainment with the current
one-hour ozone standard. The air quality modeling for the final rule shows that improvements in ozone levels are expected to occur throughout the country because of the Tier 2/ Gasoline Sulfur program. 26 EPA found that the program significantly lowers model-predicted exceedances of the
ozone standard. In 2007 the number of
exceedances in CMSA/MSAs isforecasted to decline by nearly onetenth and in 2030, when full turnover of the vehicle fleet has occurred, the program lowers such exceedances by almost one-third. In these same areas,
the total amount of ozone above the NAAQS is forecasted to decline by about 15 percent in 2007 and by more
than one-third in 2030. In the vast majority of areas, the air quality modeling predicts that the program will lower peak summer ozone
concentrations for both 2007 and 2030. The reduction in daily maximum ozone is nearly 2 ppb on average in 2007 and over 5 ppb on average in 2030. These
reductions contribute to EPA’s assessment that the program will provide the large set of public health
and environmental benefits summarized
in Section IV.D of the Preamble. The forecasted impacts of the program on
ozone in 2007 and 2030 are further described in the Tier 2 Air Quality Modeling Technical Support Document.

During the public comment period on the proposed rule, EPA received several comments that expressed concern about potential increases in ozone that might
occur as a result of this rule. As indicated above, the air quality modeling results indicate an overall
reduction in ozone levels in 2007 and 2030 during the various episodes
modeled. In addition to ozone reductions, a few areas had predicted ozone increases in portions of the area during parts of the episodes modeled. In most of these cases, we observed a net
reduction in ozone levels in these areas due to the program. In the very small number of exceptions to this, the Agency did find benefit from reduction of peak ozone levels. Based upon a careful examination of this issue, including EPA’s modeling results as well as consideration of the modeling and analyses submitted by commenters, it is clear that the significant ozone reductions from this rule outweigh the limited ozone increases that may occur.
Additional details on this issue are provided in the Response to Comments document and in the Tier 2 Air Quality Modeling Technical Support Document.

Taken together, EPA believes these
results indicate that it will be much easier for States to develop State Implementation Plans which will attainand maintain compliance with the onehour ozone standard. EPA will work with States conducting more detailed local modeling of their specific ozone situation, to ensure that their SIPs will provide attainment. Notably, there are also other upcoming federal measures to lower ozone precursors that will aid these efforts. If the State modeling of local programs shows a need, the Agency will work with states to plan further actions to produce attainment with the NAAQS in order to protect the public’s health and the environment. Further details on EPA’s modeling results can be found in the Agency’s Response to Comments and technical support documents.

C. Particulate Matter

The need to control the contribution of cars and light trucks to ambient concentrations of particulate matter (PM) is the basis for our adoption of the
new PM emission standards for vehicles. PM is also a supplemental consideration in our promulgation of


### 6716 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

27 U.S. EPA (1998) National Air Pollutant Emission Trends Update, 1970–1997. EPA–454/E–

98–007. There is evidence from ambient studies that emissions of these materials may be overestimated and/or that once emitted they have

less of an influence on monitored PM concentrations (of both PM 10 and PM2.5 ) than this inventory share would suggest. the vehicle emission standards for NOX and VOC, and for the limits on sulfur in gasoline, because SOx, NO X , and VOC are PM precursors.

For cars and for light trucks under 3750 pounds loaded vehicle weight, we are establishing new emission standards under the provisions of CAA section 202(i), which ties our action to the need
for additional emission reductions in
order to attain and maintain the NAAQS. The NAAQS relevant to the
PM emission standards is the PM 10 NAAQS. The PM 10 NAAQS also provides additional but not essential support to our promulgation of the NOX and VOC standards, since these standards are fully supportable on the basis of the 1-hour ozone NAAQS.

For the vehicles not subject to CAA 202(i), and for the gasoline sulfur limits,
our actions are tied to determinations regarding public health and welfare risks more broadly, under CAA sections 202(a), 202(b), and 211(c). The role of

NO X , VOC, and PM emissions in contributing to atmospheric
concentrations of PM 10 is an important
element of the risk that these emissions pose to public health and welfare.

PM also poses risks to public health not fully reflected in the PM 10 NAAQS. Though EPA has not relied on the adverse health impacts of fine PM to promulgate this rule, it is well established that such impacts exist. A summary of these effects is given in the next section. In addition, based on the available science, EPA’s Office of Research and Development has recently
submitted to a committee of our Science Advisory Board a draft assessment document which contains a proposed conclusion that diesel exhaust is a likely human cancer hazard and is a potential cause of other nonmalignant respiratory effects. The scientific advisory
committee has met to discuss this document, and we are awaiting written
review comments from the committee. We expect to submit a further revision of the document to the advisory
committee before we make the
document final.

1. Background on PM

Particulate matter (PM) represents a broad class of chemically and physically
diverse substances that exist as discrete particles (liquid droplets or solids) over a wide range of sizes. The NAAQS that regulates PM addresses only PM with a diameter less than or equal to 10 microns, or PM 10 . The coarse fraction of

PM 10 consists of those particles which have a diameter in the range between 2.5 and 10 microns, and the fine fraction consists of those particles which have a diameter less than or equal to 2.5 microns, or PM2.5 . These particles and droplets are produced as a direct result of human activity and natural processes, and they are also formed as secondary particles from the atmospheric
transformation of emissions of SO X , NO X , ammonia, and VOCs.

Natural sources of particles in the
coarse fraction of PM 10 include windblown dust, salt from dried sea spray, fires, biogenic emanation ( e.g., pollen from plants, fungal spores), and volcanoes. Fugitive dust and crustal material (geogenic materials) comprise approximately 80% of the coarse
fraction of the PM 10 inventory as estimated by methods in use today. 27 Manmade sources of these coarser particles arise predominantly from combustion of fossil fuel by large and small industrial sources (including power generating plants, manufacturing plants, quarries, and kilns), wind erosion from crop land, roads, and construction, dust from industrial and agricultural grinding and handling operations, metals processing, and burning of firewood and solid waste.
Coarse-fraction PM 10 remains suspended in the atmosphere a relatively short period of time.

Most of the emission sources listed for coarse particles also have a substantial fine particle fraction. Their share of the

PM2.5 inventory is somewhat smaller, however, because of the role of other sources that give rise primarily to PM2.5

. The other sources of PM2.5 include carbon-based particles emitted directly from gasoline and diesel internal combustion engines, sulfate-based particles formed from SO X and ammonia, nitrate-based particles formed
from NO X and ammonia, and carbonaceous particles formed through
transformation of VOC emissions. PM2.5 particles from fugitive dust and crustal sources comprise substantially less than their share of coarse PM emissions, approximately one-half of the directly
emitted PM2.5 inventory as estimated by methods in use today. The presence and magnitude of crustal PM2.5 in the
ambient air is much lower even than suggested by this smaller inventory share, due to the additional presence of secondary PM from non-crustal sources and the removal of a large portion of
crustal emissions close to their source.
This near-source removal results from
crustal PM’s lack of inherent thermal buoyancy, low release height, and interaction with surrounding vegetation (which acts to filter out some of these particles).

Secondary PM is dominated by sulfate particles in the eastern U.S. and parts of the western U.S., with nitrate particles and carbonaceous particles dominant in
some western areas. Mobile sources can reasonably be estimated to contribute to ambient secondary nitrate and sulfate PM in proportion to their contribution
to total NO X and SO X emissions.

The sources, ambient concentration, and chemical and physical properties of

PM 10 vary greatly with time, region, meteorology, and source category. A first step in developing a plan to attain
the PM 10 NAAQS is to disaggregate
ambient PM 10 into the basic categories of sulfate, nitrate, carbonaceous, and crustal PM, and then determine the major contributors to each category based on knowledge of local and upwind emission sources. Following this approach, SIP strategies to reduce
ambient PM concentrations have generally focused on controlling fugitive
dust from natural soil and soil disturbed by human activity, paving dirt roads and controlling soil on paved roads, reducing emissions from residential wood combustion, and controlling major stationary sources of PM 10 where applicable. The control programs to reduce stationary, area, and mobile source emissions of sulfur dioxide, oxides of nitrogen, and volatile organic compounds in order to achieve
attainment with the sulfur dioxide and ozone NAAQS also have contributed to
reductions in the fine fraction of PM 10 concentrations. In addition, the EPA
standards for PM emissions from highway and nonroad engines are contributing to reducing PM 10 concentrations. As a result of all these efforts, in the last ten years, there has
been a downward trend in PM 10 concentrations, with a leveling off in the later years.

Particulate matter, like ozone, has been linked to a range of serious respiratory health problems. Scientific studies suggest a likely causal role of ambient particulate matter in contributing to a series of health effects. The key health effects categories associated with particulate matter include premature mortality, aggravation of respiratory and cardiovascular disease (as indicated by increased hospital admissions and emergency room visits, school absences, work loss days, and restricted activity days), changes in lung function and increased respiratory symptoms, changes to lung tissues and structure, and altered respiratory defense


### 6717 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

28 U.S. EPA, 1996, Air Quality Criteria for Particulate Matter, EPA/600/P–95/001aF. Review of the National Ambient Air Quality Standards for Particulate Matter: Policy Assessment of Scientific and Technical Information, OAQPS Staff Paper, EPA–452 R–96–013, July 1996. 29 The annual average PM10 NAAQS is based on a three-year average, and the 24-hour NAAQS is based on expected exceedances over a three-year period. 30 Health Assessment Document for Diesel
Emissions, SAB Review Draft EPA/600/8–90/057D.

November 1999. The document is available electronically at http://www.epa.gov/ncea/

diesel.htm. mechanisms. PM also causes damage to materials and soiling. It is a major cause of substantial visibility impairment in many parts of the U.S.

Motor vehicle particle emissions and the particles formed by the transformation of motor vehicle gaseous emissions tend to be in the fine particle range. Fine particles are a special health concern because they easily reach the deepest recesses of the lungs. Scientific studies have linked fine particles (alone
or in combination with other air pollutants), with a series of significant health problems, including premature death; respiratory related hospital admissions and emergency room visits; aggravated asthma; acute respiratory symptoms, including aggravated coughing and difficult or painful breathing; chronic bronchitis; and decreased lung function that can be experienced as shortness of breath.

These effects are discussed further in EPA’s ‘‘Staff Paper’’ and ‘‘Air Quality Criteria Document’’ for particulate

matter. 28

EPA first established primary (healthbased) and secondary (welfare-based) National Ambient Air Quality Standards
for PM 10 in 1987. The annual and 24- hour primary PM 10 standards were set at

50 μg/m 33 , and 150 μg/m 3

, respectively. 29 In July 1997, the primary
standards were revised to add two new

PM2.5 standards. At the same time, we changed the statistical form of the primary PM 10 standard and set all the secondary standards to be the same as the primary.

On May 14, 1999, a panel of the U.S. Court of Appeals for the District of
Columbia Circuit reviewed EPA’s revisions to the ozone and PM NAAQS and found, by a 2–1 vote, that sections 108 and 109 of the Clean Air Act, as interpreted by EPA, represent unconstitutional delegations of Congressional power. American Trucking Ass’ns, Inc., et al., v. Environmental Protection Agency, 175 F.3d 1027 (D.C. Cir. 1999). Among other things the Court remanded the record for the 8-hour ozone NAAQS and the

PM2.5 NAAQS to EPA. On October 29, 1999, EPA’s petition for rehearing by the three judge panel was denied, with an exception regarding the revised ozone NAAQS. EPA’s petition for rehearing en banc by the full Circuit was also denied, although five of the nine judges considering the petition agreed to rehear
the case.

The pre-existing PM 10 NAAQS remains in effect (except for one area— Boise, ID—where prior to the court’s decision we had determined it no longer to apply). We believe that given the
uncertain status of the new PM2.5 NAAQS, it is most appropriate to rely primarily on the pre-existing PM 10 NAAQS in establishing the Tier 2/ Gasoline Sulfur program’s vehicle
emission standards and limits on sulfur in gasoline. However, because we believe, and the Court did not dispute, that there are very substantial public
health risks from PM2.5 and substantial
health and economic benefits from reducing PM2.5 concentrations, we have conducted analyses of the PM2.5 changes likely to occur from the Tier 2/Gasoline Sulfur program. These analyses are
summarized in the section of this preamble dealing with the economic benefits of the new standards, section IV.D.5, and corresponding sections of
the final RIA. There is additional concern regarding

the health effects of PM from diesel vehicles, apart from the health effects which were considered in setting the NAAQS for PM 10 and PM2.5 . Diesel PM contains small quantities of chemical species that are known carcinogens, and

diesel PM as a whole has been implicated in occupational epidemiology studies. EPA’s Office of Research and Development has considered these studies, and has recently submitted to a committee of our Science Advisory Board a draft

conclusion that diesel exhaust is a ‘‘highly likely’’ human cancer hazard. 30 Because we are awaiting a formal response from our advisory committee before revising and finalizing our assessment document, we are not relying on the conclusions in this document as formal support for our action today. More information about this aspect of PM air quality is given in section III.F of this preamble.

2. Need for Additional Reductions to

Attain and Maintain the PM 10 NAAQS

The most recent PM 10 monitoring data indicates that 15 designated PM 10 nonattainment counties, with a population of almost 9 million in 1996,

violated the PM 10 NAAQS in the period 1996–1998. The areas that are violating

do so because of exceedances of the 24-

hour PM 10 NAAQS. No areas had

monitored violations of the annual standard in this period. Table III.C–1

lists the 15 counties. The table also

indicates the classification for each area

and the status of our review of the State Implementation Plan.



### TABLE 

### III.C–1.—F IFTEEN 

### PM 10 

### N ONATTAINMENT 

### A REAS 

### V IOLATING THE 

### PM 10 

### NAAQS IN 

### 1996–1998

a

Area Classification SIP approved? 1996 Population (millions)

Clark Co., NV ................................................................................................................. S erious .................... No ..................... 0.93 El Paso, TX .................................................................................................................... Moderate ................. Yes ................... 0.67 Gila, AZ ....................................................................................................................... .... Moderate ................. No ..................... 0.05 Imperial Co., CA ............................................................................................................. Moderate ................. No ..................... 0.14 Inyo Co., CA ................................................................................................................... Moderate ................. No ..................... 0.02 Kern Co., CA .................................................................................................................. S erious .................... No ..................... 0.62 Mono Co., CA ................................................................................................................. Moderate ................. No ..................... 0.01 Kings Co., CA ................................................................................................................. S erious .................... No ..................... 0.11 Maricopa Co., AZ ........................................................................................................... Seri ous .................... No ..................... 2.61 Power Co., ID ................................................................................................................. M oderate ................. No ..................... 0.01 Riverside Co., CA ........................................................................................................... Serious .................... No ..................... 1.41 San Bernardino Co., CA ................................................................................................. Serious . ................... No ..................... 1.59 Santa Cruz Co., AZ ........................................................................................................ Moderate ................. No ..................... 0.04 Tulare Co., CA ................................................................................................................ S erious .................... No ..................... 0.35


### 6718 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

31 Regulatory Impact Analyses for the Particulate Matter and Ozone National Ambient Air Quality Standards and Proposed Regional Haze Rule, Innovative Strategies and Economics Group, Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, N.C., July 16, 1997. 32 We used the more recent modeling for 2030 rather than the earlier modeling for 2010, because the modeling the 2030 incorporates more recent

estimates of emissions inventories. Our emission

estimates in our final RIA indicate that PM 10 emissions under the basline scenario increase steadily between 1996 and 2030, for 47 states combined and for four specific cities, suggesting

that areas in nonattainment in both 1996–1998 and

2030 will be in nonatainment in the intermediate years as well assuming no further emission reductions. A factor tending to make Table III.C–2

shorter is that we have not relied on the sourcereceptor matrix model’s prediction of 24-hour nonattainment, as those predictions on an

individual areas basis are less reliable than the predictions of annual average nonattainment. 

### TABLE 

### III.C–1.—F IFTEEN 

### PM 10 

### N ONATTAINMENT 

### A REAS 

### V IOLATING THE 

### PM 10 

### NAAQS IN 

### 1996–1998

a

### —Continued

Area Classification SIP approved? 1996 Population (millions)

Walla Walla Co., WA ...................................................................................................... Moderate ................. Yes ................... 0.05 Total Population ................................................................................................... ............ ................. ...................... 8.61

a Although we do not believe that we are limited to considering only designated nonattainment areas in implementing CAA section 2 02(i), we have focused on the designated areas in the case of PM 10 . An official designation of PM 10 nonattainment indicates the existence of a confirmed
PM 10 problem that is more than a result of a one-time monitoring upset or a results of PM 10 exceedances attributable to natural events. In addition to these designated nonattainment areas, there are 15 unclassified counties in 12 geographically spread out states, with a1996 population of over 4 million, for which the state has reported PM 10 monitoring data for this period indicating a PM 10 NAAQS violation. We have not yet excluded the possibility that a one-time monitoring upset or a natural event(s) is responsible for the monitored violations in 19 96–1998 in the 15 unclassified counties. We adopted a policy in 1996 that allows areas whose PM 10 exceedances are attributable to natural events to remain unclassified if the state is taking all reasonable measures to safeguard public health regardless of the source of PM 10 emissions. Areas that remain unclassified areas are not required to submit attainment plans, but we work with each of these areas to understand the nature of the PM 10 problem and to determine what best can be done to reduce it. The Tier 2/Gasoline Sulfur program will reduce PM 10 concentrations in these 15 unclassified counties, because all have car and light truck travel that contributes to PM 10 and precursor emissions loadings. This reduction will assist these areas in reducing their PM 10 nonattainment problem, if a problem is confirmed upon closer examination of each local situation. Boise, ID, had also been classified as a PM 10 nonattainment area at one time and was monitored to have a PM 10 NAAQS violation in 1996–1998. However, the pre-existing PM 10 NAAQS does not presently apply in Boise, ID, because in the period between our revision of the old PM 10 NAAQS and the Court’s decision to vacate the revised PM 10 NAAQS, we determined that Boise was in attainment with the old PM 10 NAAQS and that it therefore no longer applied in that area.

Because the types and sources of PM 10 are complex and vary from area to area, the best projections of future PM 10 concentrations are the local emission inventory and air quality modeling analyses that states have developed or are still in the process of developing for
their PM 10 attainment plans. We do employ a modeling approach, known as the source-receptor matrix approach, for relating emission reductions to PM 10 reductions on a national scale. This approach is one of our established air quality models for purposes of quantifying the health and welfare
related economic benefits of PM reductions from major regulatory actions. One application of this modeling approach was for the Regulatory Impact Analysis for the establishment of the new PM NAAQS 31

. This model is also the basis for the
estimates of PM 10 (and PM2.5 )
concentrations reductions we have used
to estimate the economic benefits of the Tier 2/Gasoline Sulfur program in 2030. Its use for this purpose is described in the final RIA. In both applications, we
modeled an emissions scenario corresponding to controls currently in place or committed to by states. As such, this scenario is an appropriate baseline for determining if further
reductions in emissions are needed in
order to attain and maintain the PM 10 NAAQS.

In the RIA for the establishment of the PM NAAQS, we projected that in 2010 there will be 45 counties not in attainment with the original PM 10 NAAQS . We cited these modeling results in our proposal for the Tier 2/ Gasoline Sulfur program and in our first supplemental notice. After reviewing public comments on our presentation of these modeling results, we have
concluded that while the sourcereceptor matrix approach is a suitable model for estimating PM concentration
reductions for economic benefits estimation, it is not a tool we can use with high confidence for predicting that
individual areas that are now in
attainment will become nonattainment in the future. However, we believe the source-receptor matrix approach is appropriate for, and is a suitable tool for, determining that a current designated nonattainment area has a high risk of remaining in PM 10 nonattainment at a future date. Therefore, we have cross-matched the
results for 2030 from our final RIA for
Tier 2 and the list of current PM 10 nonattainment areas with monitored
violations in 1996 to 1998 shown in
Table III.C–1. 32 Based on this, we
conclude that the 8 areas shown in Table III.C–2 have a high risk of failing
to attain and maintain without further
emission reductions. These areas have a population of nearly 8 million. Included in the group are the counties that are part of the Los Angeles, Phoenix, and Las Vegas metropolitan areas, where traffic from cars and light trucks is
substantial. California areas will benefit from the Tier 2/Gasoline Sulfur program because of travel within California by vehicles originally sold outside the state, and by reduced poisoning of catalysts from fuel purchased outside of
California.



### TABLE 

### III.C–2.—E IGHT 

### A REAS 

### W ITH A 

### H IGH 

### R ISK OF 

### FAILING 

### TO 

### ATTAIN

AND 

### M AINTAIN THE 

### PM 10 

### NAAQS

W ITHOUT 

### F URTHER 

### R EDUCTIONS IN 

### E MISSIONS

Area 1996 population (millions)

Clark Co., NV ........................... 0.93 Imperial Co., CA ....................... 0.14 Kern Co., CA ............................ 0.62 Kings Co., CA ........................... 0.11 Maricopa Co., AZ ..................... 2.61 Riverside Co., CA ..................... 1.41 San Bernardino Co., CA ........... 1.59 Tulare Co., CA .......................... 0.35

Total population ............. 7.76

Table III.C–2 is limited to designated

PM 10 nonattainment areas which both
had monitored violations of the PM 10 NAAQs in 1996–1998 and are predicted
to be in nonattainment in 2030 in our

PM 10 air quality modeling. This gives us high confidence that these areas require
further emission reductions to attain and maintain, but does not fully


### 6719 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

33 In fact, in two of these areas, New York Co., NY and Harris Co., TX, the average PM 10 level in
1998 was above the 50 μg/m 3 value of the NAAQS.
These two areas are not included in the Table III.C– 2 list of areas with a high risk of failing to attain
and maintain because lower PM 10 levels in 1996 and 1997 caused their three-year average PM 10 level to be lower than the NAAQS. Official
nonattainment determinations for the annual PM 10 NAAQS are made based on the average of 12 quarterly PM 10 averages. consider the possibility that there are other areas which are now meeting the

PM 10 NAAQS which have at least a significant probability of requiring
further reductions to continue to maintain it. Our air quality modeling predicted 2030 violations of the annual average PM 10 NAAQS in five additional
counties that in either 1997 or 1998 had single-year annual average monitored

PM 10 levels of at least 90 percent of the NAAQS, but did not exceed the formaldefinition of the NAAQS over the threeyear period ending in 1998 33 . These areas are shown in Table III.C–3. They have a combined population of almost 17 million, and a broad geographic spread. Unlike the situation for ozone, for which precursor emissions are generally declining over the next 10 years or so before beginning to increase,
we estimate that emissions of PM 10 will rise steadily unless new controls are implemented. The small margin of attainment which these areas currently enjoy will likely erode; the PM air quality modeling suggests that it will be
reversed. We therefore consider these areas to each individually have a significant risk of failing to maintain the NAAQS without further emission
reductions. There is a substantial risk
that at least some of them would fail to
maintain without further emission
reductions. The emission reductions from the Tier 2/Gasoline Sulfur program will help to keep them in attainment.



### TABLE 

### III.C–3.—F IVE 

### A REAS 

### W ITH A 

### S IGNIFICANT 

### R ISK OF 

### FAILING TO 

### ATTAIN AND 

### M AINTAIN THE 

### PM 10 

### NAAQS W ITHOUT 

### F URTHER 

### R EDUC



### TIONS IN 

### E MISSIONS

Area 1996 population (millions)

New York Co., NY .................... 1.33 Cuyahoga Co., OH ................... 1.39 Harris, Co., TX .......................... 3.10 San Diego Co., CA ................... 2.67 Los Angeles Co., CA ................ 8.11

Total population ............. 16.6

Taken together and considering their number, size, and geographic distribution, these 13 areas are sufficient
to establish the case that additional reductions are needed in order to attain
and maintain the PM 10 NAAQS. This determination provides additional support for the NOx and VOC standards and for the limits on gasoline sulfur, which are also fully supported on ozone
attainment and health effects considerations. The sulfate particulate, sulfur dioxide, NO X , and VOC emission
reductions from the Tier 2/Gasoline Sulfur program will help the 8 areas in
Table III.C–2 and the 5 areas in Table
III.C.–3 to attain and maintain the PM 10 NAAQS. The new PM standards for gasoline and diesel vehicles are also supported by this PM 10 determination.

We are also establishing the new PM emissions standard today to avoid the possibility that PM 10 concentrations in these and other areas do get even worse
due to an increase in sales of diesel vehicles, which could create a need for
further reductions which would be larger and would affect more areas of the country. At the present time, virtually all cars and light trucks being sold are gasoline fueled. The ambient

PM 10 air quality data for 1996 to 1998 reflects that current situation, and this data was an important factor in what
areas are listed in Tables III.C–2 and III.C–3. Also, the predictions of future

PM 10 air quality, used to develop the
Tables III.C–2 and III.C–3 lists of areas with high or significant risk of being unable to attain and maintain, are based on an assumption that this will continue to be true. However, we are concerned over the possibility that diesels will become more prevalent in the car and light-duty truck fleet, since automotive companies have announced their desire
to increase their sales of diesel cars and light trucks. Because current diesel vehicles emit higher levels of PM 10 than gasoline vehicles, a larger number of diesel vehicles could dramatically
increase levels of exhaust PM 10 , especially if more stringent PM emissions standards are not in place.
The new PM emissions standards will
ensure that an increase in the sales of diesel cars and light trucks will not
increase PM emissions from cars and light trucks so substantially as to endanger PM 10 attainment and maintenance on a more widespread basis. Given this potential, it is appropriate to establish the new PM
emissions standards now on the basis of
the increase in sales of diesel vehicles being a reasonable possibility without such standards. Establishing the new
PM emissions standards now avoids the public health impact and industry disruption that could result if we waited
until an increase in sales of diesels with high PM emissions had already
occurred.

In order to assess the potential impact of increased diesel sales penetration on PM emissions, we analyzed the increase

in PM 10 emissions from cars and trucks
under a scenario in which the use of diesel engines in cars and light trucks increases. We used projections developed by A.D. Little, Inc. as part of a study conducted for the American Petroleum Institute. The ‘‘Most Likely’’ case projected by A.D. Little forecasts that diesel engines’’ share of the light truck market will grow to 24 percent by the 2015 model year. Diesel engines’ share of the car market would grow somewhat more slowly, reaching 9 percent by 2015. The A.D. Little forecasts did not address the period after 2015; we have assumed that diesel
sales stabilize at the level reached in 2015, with the fraction of in-use vehicles with diesel engines continuing to increase through turnover. We believe these projections are more realistic than the scenario of even higher sales of
diesels described in the notice for the proposed Tier 2/Gasoline Sulfur program, though the A.D. Little forecasts still show much higher percentages of diesel vehicles in the light-duty fleet than have ever existed historically in
the U.S.

The A.D. Little scenario of increased diesels, and even more so the scenario described in our proposal, would result
in dramatic increases in direct PM 10 emissions from cars and light trucks, if there were no change in these vehicles’
PM standards. The increase in diesel
exhaust PM 10 emissions would more
than overcome the reduction in direct

PM 10 attributable to the sulfur reduction in gasoline. With no change in the existing PM standards for cars and light trucks, our analysis of this scenario
shows that direct PM 10 emissions in 2020 would be approximately 98,000 tons per year, which is nearly two times the 50,000 tons projected if diesel sales do not increase. The portion of ambient

PM 10 concentrations attributable to cars and light trucks would climb steadily. The final RIA presents alternative estimates of the amount by which future

PM 10 concentrations could increase due to such an emissions increase, based on extrapolations from several studies’estimates of the contribution that heavyduty diesel vehicles have made to recent

or PM 10 concentrations. The increase is estimated to range from 0.6 to 20 μg/m3.

The added PM 10 emissions from cars
and trucks due to an increase in diesel
sales without action to reduce PM 10 from new diesel vehicles would
exacerbate the PM 10 nonattainment problems of the areas listed in Tables


### 6720 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

III.C–2 and III.C–3, for which our air quality modeling predicted future

nonattainment even without an increase in diesel sales. Moreover, it might cause

PM 10 nonattainment in additional areas. In addition to the counties already listed in Tables III.C–2 and III.C–3, there are

other areas for which 1997 and 1998

data indicate that maintenance of the

PM 10 NAAQS is at risk if diesel sales of cars and light truck increase. Table

III.C–4 lists additional counties for which either 1997 or 1998 monitoring data, or both, indicated a second-high

PM 10 concentration for the single year within 10 percent of the PM 10 24-hour NAAQS or an annual average PM 10 concentration within 10 percent of the annual average PM 10 NAAQS. Only counties which are part of metropolitan

statistical areas are listed in Table III.C– 4, in order to focus on those in which traffic densities are high. Considering both the annual and 24-hour NAAQS, there were 13 areas within 10 percent of

the standard. Increases in PM 10 emissions from more diesel vehicles would put these areas in greater risk of violating the PM 10 NAAQS, especially if growth in other sources is high or meteorological conditions are more adverse than in the 1996 to 1998 period.

TABLE III.C–4.—T HIRTEEN M ETROPOLITAN STA

TISTICAL A REA C OUNTIES W ITH 1997 AND/OR 1998 A MBIENT PM 10 Concentrations Within

10 Percent of the Annual or 24-Hour the

PM 10 NAAQS

a

1996 population (millions)

Areas within 10 percent of the annual PM 10 NAAQS:

Lexington Co., SC ........................... 0.20 Union Co., TN ................................. 0.02 Washoe Co., NV ............................. 0.30 Madison Co., IL ............................... 0.26 Dona Ana Co., NM .......................... 0.16 El Paso Co., TX .............................. 0.68 Ellis Co., TX .................................... 0.97 Fresno Co., CA ............................... 0.74 Philadelphia Co., PA ....................... 1.47

Areas within 10 percent of the 24-hour PM 10 NAAQS:

Lexington Co., SC ........................... 0.20 El Paso Co., TX .............................. 0.68 Union Co., TN ................................. 0.02 Mobile Co., AL ................................ 0.40 Dona Ana Co., NM .......................... 0.16 Lake Co., IN .................................... 0.48 Philadelphia Co., PA ....................... 1.47 Pennington Co., SD ........................ 0.09 Ventura Co., CA .............................. 0.71

Total Population of all 13

areas ................................. 6.48

Notes: a These areas are listed based on their secondhigh 24-hour concentration and annual average concentration in 1997, 1998, or both. Official nonattainment determinations are made based on three years of data, and on estimates of expected exceedances of the 24-hour standard.

Fortunately, the standards included in today’s actions will result in a steady
decrease in total direct PM 10 from cars and light trucks even if this increase in the use of diesel engines in these
vehicles were to occur. If the A.D. Little ‘‘Most Likely’’ scenario for increased diesel engines in light trucks were to occur, today’s actions would reduce
diesel PM 10 from cars and light trucks by over 75 percent in 2020. Stated differently, by 2030 today’s actions would reduce 98,000 tons of the potential increase in PM 10 emissions from passenger cars and light trucks.
The result would be less direct PM 10 than is emitted today, because the
increase in diesel PM 10 would be more than offset by the reduction in PM 10 emissions from gasoline vehicles resulting from lower gasoline sulfur
levels.

We are establishing tighter PM standards for cars and light trucks to help avoid the adverse impact of greater
diesel PM emissions on PM 10 attainment and public health and welfare if diesel
sales increased in the future without the protection of the tighter standards. Because diesel vehicles will essentially be performing the same functions as the gasoline vehicles they will replace, it is appropriate for the new PM standards to also apply equally to gasoline and diesel vehicles. We expect that gasoline vehicles will need little or no redesign
to meet the new PM standards when free of defects and properly operating. However, the new vehicle and gasoline sulfur standards may achieve some
reduction in real world PM emissions from gasoline vehicles by encouraging more durable designs and by ensuring that these vehicles are operated on
lower-sulfur fuel. The new standards for PM will also prevent any changes in gasoline engine design which would increase PM emissions. These changes would otherwise be possible because
the current PM standard is so much higher than the current performance on the gasoline vehicles.

3. PM2.5 Discussion

We are not basing our promulgation of the Tier 2 vehicle standards on a finding
on the need for additional emission
reductions in order to attain and maintain the NAAQS for PM2.5 . We are providing this information to explain that this program will result in
substantial benefit in reduction of PM2.5 concentrations, to an even broader set of geographic areas than will benefit in
terms of PM 10 attainment.

The annual and 24-hour PM2.5 NAAQS set in 1997 are numerically much lower than the corresponding

PM 10 standards: 15 versus 50 μg/m 3 for the annual average standards and 65

versus 150 μg/m 3 for the 24-hour average standards. While geographically
broad PM2.5 monitoring is just now reaching the end of the first of three years of operation needed to determine compliance, our best analysis from the
more limited PM2.5 conducted in some areas indicates that many areas that are in compliance with the PM 10 standards
will be found to be in violation of the annual average PM2.5 standard.
Violations of the 24-hour PM2.5 standard appear to be infrequent.

Therefore, if we considered it appropriate to proceed with implementing the PM2.5 NAAQS, we are confident that there would be a larger
set of areas for which we would
determine that further reductions in
emissions are needed in order to attain and maintain the NAAQS.

Moreover, gasoline and diesel cars and light trucks have a more important contributing role for ambient PM2.5 concentrations, and other emission sources that play a major role in
ambient PM 10 concentrations will be relatively less important. Cars and light trucks contribute essentially the same
absolute amount to ambient
concentrations of PM 10 and of PM2.5

. However, most other sources contribute
much more to PM 10 than to PM2.5 , so the relative contribution from cars and light trucks is larger. In addition, the absolute contribution from cars and light trucks is larger in relationship to the numerically lower PM2.5 standard, making them more important to
attainment and maintenance. This is also true for the potential contribution that more diesel cars and light trucks
would make to ambient PM2.5 concentrations.

4. Emission Reductions and Ambient
PM Reductions

The NO X and VOC emission
reductions from the Tier 2/Gasoline Sulfur program are presented in the
ozone section above. The SO X and PM reductions are presented in our final RIA, and are essentially unchanged from those presented in our proposal, except
for the revision of the diesel sales
scenario discussed above.

Because virtually all of the PM
reduction from the Tier 2/Gasoline


### 6721 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

34 ‘‘National Parks and the American Public: A National Public Opinion Survey on the National Park System,’’ Summary Report, National Parks and Conservation Association, June 1998. 35 ‘‘Recommendations for Improving Western Vistas,’’ Report of the Grand Canyon Visibility Transport Commission to the United States Environmental Protection Agency, June 10, 1996. Sulfur program is in the fine fraction of

PM 10 , our estimates of the PM2.5 and

PM 10 reductions are essentially the
same. Estimates of the ambient PM reductions in 2030 in different parts of the nation, after full phase in of the vehicle standards, are presented in the
final RIA. The reductions in ambient PM are largest in the parts of the country with more vehicle travel, i.e, larger in the east than in the west and larger in urban areas than in rural areas. In the eastern half of the nation, the reductions in annual average PM concentrations range from 0.2 to over 1.2 micrograms per cubic meter.

D. Other Criteria Pollutants: Carbon Monoxide, Nitrogen Dioxide, Sulfur
Dioxide

The standards being promulgated today will help reduce levels of three other pollutants for which NAAQSs
have been established: carbon monoxide (CO), nitrogen dioxide (NO 2), and sulfur dioxide (SO 2). As of 1998, every area in the United States has been designated to
be in attainment with the NO 2 NAAQS. As of 1997, one area (Buchanan County, Missouri) did not meet the primary SO 2 short-term standard, due to emissions from the local power plant. There are currently 20 designated CO nonattainment areas, with a combined population of 33 million. There are also 24 designated maintenance areas with a combined population of 22 million. However, the broad trends indicate that ambient levels of CO are declining. In 1997, 6 of 537 monitoring sites reported
ambient CO levels in excess of the CO NAAQS.

The reductions in SO 2 precursor emissions from today’s actions are essentially equal to the SO X reductions described in Section III.B. and III.C., respectively. The impact of today’s

actions on NO 2 emissions depends on the specific emission control technologies used to meet the Tier 2 vehicle emission standards. However, essentially all of the NO X emitted by cars and light trucks converts to NO 2 in the atmosphere; therefore, it is reasonable to assume that today’s actions will substantially reduce
ambient NO 2 levels by the same proportion. Today’s rule also will require light trucks to meet more stringent CO standards. These more stringent standards will help extend the
trend towards lower CO emissions from motor vehicles and thereby help the remaining CO nonattainment areas reach attainment while helping other
areas remain in attainment with the CO NAAQS. Our analysis of CO reductions from today’s program is found in Chapter III of the RIA. The analysis of economic benefits and costs found in
Section IV.D.–5. does not account for
the economic benefits of the CO reductions expected to result from today’s proposal.

E. Visibility

Visibility impairment occurs as a result of the scattering and absorption of light by particles and gases in the atmosphere. It is most simply described as the haze that obscures the clarity, color, texture, and form of what we see. The principal cause of visibility reduction is fine particles between 0.1
and 1 μm in size. Of the pollutant gases, only NO 2 absorbs significant amounts of light; it is partly responsible for the brownish cast of polluted skies. While
the contribution of NO 2 to visibility impairment varies from area to area, it is generally responsible for less than ten percent of visibility reduction.

The CAA requires EPA to protect visibility, or visual air quality, through a number of programs. These programs include the national visibility program
under Sections 169a and 169b of the Act, the Prevention of Significant Deterioration program for the review of potential impacts from new and modified sources, and the secondary NAAQS for PM 10 and PM2.5 . The national visibility program established in 1980 requires the protection of visibility in 156 mandatory federal Class I areas across the country (primarily national parks and wilderness areas).
More than 65 million visitors travel each year to these parks and wilderness
areas. The CAA established as a national visibility goal, ‘‘the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory federal Class I areas in which impairment results from manmade air pollution.’’ The Act also calls for state programs to make ‘‘reasonable progress’’ toward the national goal. In addition, a recent national opinion poll on the state of the national parks found that more than 80 percent of Americans believe air pollution affecting these parks should be cleaned up for the benefit of future generations. 34

There has been improvement in visibility in the western part of the country over the last ten years. However, visibility impairment remains a serious problem in Class I areas. Visibility in the East does not seem to have improved. As one part of addressing this national problem, EPA has required states to adopt and implement effective plans for protecting and improving visibility in Class I federal areas (64 FR 35714, July 1, 1999).

Today’s actions will result in visibility improvements due to the reduction in local and upwind PM and PM precursor emissions. Since mobile
source emissions contribute to the formation of visibility-reducing PM, control programs that reduce the mobile
source emissions of direct and secondary PM would have the effect of improving visibility. The Grand Canyon Visibility Transport Commission’s final recommendations report 35 found that reducing total mobile source emissions is an essential part of any program to protect visibility in the Western U.S.
The Commission found that motor vehicle exhaust is responsible for about 14 percent of human-caused visibility reduction (excluding road dust). A substantial portion of motor vehicle exhaust comes from cars and light trucks. In light of that impact, the
Commission’s recommendations in 1996 supported federal Tier 2/Gasoline Sulfur standards, as EPA is proposing today. More recently, a number of Western Governors noted the importance of controlling mobile sources as part of efforts to improve visibility in their comments on the Regional Haze Rule and on the need to protect the 16 Class
I areas on the Colorado Plateau. In their joint letter dated June 29, 1998, they stated that, ‘‘* * * the federal government must do its part in regulating emissions from mobile sources that contribute to regional haze
in these areas. * * *’’ and called on EPA to make a ‘‘binding commitment * * * to fully consider the
Commission’s recommendations related
to the * * * federal national mobile source emission control strategies.’’
These recommendations included Tier 2
vehicle standards and reductions in gasoline sulfur levels.

The recent Northern Front Range Air Quality Study provides another indication of how important car and light truck emissions can be to fine PM and visibility. This study reported findings that indicate that cars and light trucks are responsible for 39 percent of fine PM at a site within the metropolitan Denver area, and for 40 percent at a
downwind rural site. This contribution
includes both direct PM and indirect
PM formed from sulfur dioxide and

NO X from these vehicles.


### 6722 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

36 EPA’s diesel health assessment (Health Assessment Document for Diesel Emissions, SAB Review Draft, U.S. Environmental Protection Agency, Washington, DC. EPA/600/8–90/057D, November 1999) can be found at the following EPA

website: http://www.epa.gov/ncea/diesel.htm.

37 National Institute for Occupational Safety and Health (1988) Carcinogenic effects of exposure to diesel exhaust. NIOSH Current Intelligence Bulletin 50. DHHS (NIOSH) Publication No. 88–116. Centers for Disease Control, Atlanta, GA.

International Agency for Research on Cancer (1989) Diesel and gasoline engine exhausts and some nitroarenes, Vol. 46. Monographs on the evaluation of carcinogenic risks to humans. World Health Organization, International Agency for Research on Cancer, Lyon, France.

World Health Organization (1996) Diesel fuel and exhaust emissions: International program on chemical safety. World Health Organization, Geneva, Switzerland.

California Environmental Protection Agency,

Office of Environmental Health Hazard Assessment: Proposed Identification of Diesel Exhaust as a Toxic Air Contaminant, Part B Health Risk Assessment for Diesel Exhaust. April 22, 1998.

38 California Environmental Protection Agency,

Office of Environmental Health Hazard Assessment: Proposed Identification of Diesel Exhaust as a Toxic Air Contaminant, Part B Health Risk Assessment for Diesel Exhaust. April 22, 1998.

39 ‘‘U.S. Light-Duty Dieselization Scenarios— Preliminary Study’’, report to the American Petroleum Institute, July 2, 1999. Prepared by Arthur D. Little, Inc. The analysis of economic benefits and
costs found in Section IV.D.5. accounts
for the economic benefits of the visibility improvements expected to result from today’s actions.

F. Air Toxics

Section 202(a) provides that EPA may promulgate standards regulating any air pollutants that in the Administrator’s judgment, cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare. Section 202(l) provides specific provisions for regulation of hazardous air pollutants from motor vehicles and fuels, and states that at a minimum such regulations should apply to emissions of benzene and formaldehyde.

Emissions from cars and light trucks include a number of air pollutants that are known or suspected human or animal carcinogens or that are known or suspected to have other, non-cancer health impacts. These pollutants include benzene, formaldehyde, acetaldehyde, 1,3-butadiene, and diesel particulate matter. For several of these pollutants, motor vehicle emissions are believed to account for a significant proportion of total nation-wide emissions. All of these compounds are present in exhaust emissions; benzene is also found in evaporative emissions from gasoline-fueled vehicles.

The health effects of diesel particulate matter are of particular relevance to today’s actions, because of the possibility for increased diesel-powered truck sales and the more stringent PM standard that will apply to these trucks as a result of today’s actions. While we
have not finalized our decision about the carcinogenicity of diesel exhaust, we are in the process of addressing this question. The Agency’s recently
released draft assessment 36 concludes that diesel exhaust is a highly likely human lung cancer hazard, but that the data are currently unsuitable to make a confident quantitative statement of risk. The draft report concludes, however, that this risk is applicable to ambient exposures and that the risk may be in the range of regulatory interest (greater than one in a million over a lifetime). Several other agencies and governing bodies have designated diesel exhaust or diesel PM as a ‘‘potential’’ or ‘‘probable’’ human carcinogen. 37 The California Air Resources Board (ARB), for example, found that diesel particulate matter constituted a toxic air contaminant and estimated a potency range of 1.3 × 10

¥ 4 to 2.4 × 10

¥ 3 per μg/

m 3

. 38 The ARB’s findings suggest that 130 to 2400 persons in one million exposed to 1 μg/m 3 of diesel exhaust particulate continuously for their lifetime (70 years) would develop cancer as a result of their exposure.

Because our assessment for diesel exhaust is not complete, we are not presenting absolute estimates of how potential cancer risks from diesel particulate matter could be affected by today’s rule. However, we can offer a qualitative or relative discussion of these risks. Diesel engines used in nonroad equipment and heavy-duty highway vehicles currently constitute a far larger source of diesel PM than cars and light-duty trucks, since diesel engines are used in a very small portion of the cars and light-duty trucks in service today. However, engine and vehicle manufacturers have projected that diesel engines are likely to be used in an increasing share of cars and light trucks, and some manufacturers have announced capital investments to build such engines.

If these projections are valid, then the proportion of cars and light trucks powered by diesel engines, and the associated potential health risks from diesel PM, could increase substantially. We modeled the most likely level of increase in light duty diesel engine sales developed for the American Petroleum

Institute. 39 We found that the greater diesel engine usage in cars and light trucks resulted in an 80 percent increase in emissions from all diesel-powered highway vehicles by 2020—emissions that have been implicated in potential cancer risks—assuming no change in the current light-duty diesel PM standards.

Today’s rule would limit the increase in the potential cancer risks from cars and light trucks associated with any potential increase in light-duty diesel engines. Using the same sales projections discussed above, we have estimated that today’s rule would limit the increase in total highway diesel PM emissions in 2020 due to growth in light duty diesels to under 10 percent, in contrast to the 80 percent increase projected to occur without the Tier 2 PM standards. An analogous analysis that accounted for exposure patterns, but that assumed even more widespread use of diesels in the car and light truck fleet, found that today’s rule would limit the increase in total highway diesel PM exposure to about 8 percent. This analysis is discussed more fully in Chapter III.F.2 of the Regulatory Impact Analysis. In addition, the VOC emission reductions resulting from today’s rule would reduce the potential cancer risk posed by air pollutants other than diesel PM emitted by cars and light trucks, since many of these pollutants are themselves VOCs. Furthermore, the rule would align the formaldehyde standards

for all Tier 2 LDVs and LDTs with the formaldehyde standards for LDVs and LDT1s from the NLEV program, thereby helping to harmonize the Federal and California formaldehyde standards.

The analysis of economic benefits and

costs found in Section IV.D.5. does not

account for the economic benefits of the

reduction in cancer risk from air toxics that could result from today’s rule. Although we have completed a peer reviewed assessment of the impact of today’s rule on exposure to toxic emissions, we have not engaged in a peer-reviewed assessment of the baseline air toxics risks (including a final quantitative risk assessment of the diesel particulate risks) or of the reductions that would be achieved by today’s rule.

We plan to complete our analysis of air toxics risks as part of our responsibilities under section 202(l)(2) of the Clean Air Act, which requires EPA to establish regulations for the control of hazardous air pollutants from motor vehicles. The regulations may

address vehicle emissions or fuel properties that influence emissions, or both. We plan to issue a proposal to address this requirement in April 2000,

and a final rule in December 2000.


### 6723 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

40 Much of the information in this section was excerpted from the EPA document, Human Health Benefits from Sulfate Reduction, written under Title IV of the 1990 Clean Air Act. Amendments, U.S. EPA, Office of Air and Radiation, Acid Rain Division, Washington, DC, November 1995. 41 Vitousek, Peter M., John Aber, Robert W. Howarth, Gene E. Likens, et al. 1997. Human Alteration of the Global Nitrogen Cycle: Causes and Consequences. Issues in Ecology. Published by Ecological Society of America, Number 1, Spring

1997. 42 Much of this information was taken from the following EPA documenta: Deposition of Air Pollutants to the Great Waters-Second Report to Congress, Office of Air Quality Planning and Standards, June 1997, EPA–453/R–97–011.

43 Terrestrial nitrogen deposition can act as a fertilizer. In some agricultural areas, this effect can

be beneficial. G. Acid Deposition 40

Acid deposition, or acid rain as it is commonly known, occurs when SO 2 and NO X react in the atmosphere with water, oxygen, and oxidants to form various acidic compounds that later fall to earth in the form of precipitation or dry deposition of acidic particles. It contributes to damage of trees at high elevations and in extreme cases may
cause lakes and streams to become so acidic that they cannot support aquatic life. In addition, acid deposition accelerates the decay of building materials and paints, including irreplaceable buildings, statues, and sculptures that are part of our nation’s cultural heritage. To reduce damage to automotive paint caused by acid rain and acidic dry deposition, some manufacturers use acid-resistant paints, at an average cost of $5 per vehicle—a total of $61 million per year if applied
to all new cars and trucks sold in the U.S. The general economic and
environmental effects of acid rain are discussed at length in the RIA.

Acid deposition primarily affects bodies of water that rest atop soil with a limited ability to neutralize acidic compounds. The National Surface Water Survey (NSWS) investigated the effects of acidic deposition in over 1,000 lakes larger than 10 acres and in thousands of
miles of streams. It found that acid deposition was the primary cause of acidity in 75 percent of the acidic lakes and about 50 percent of the acidic streams, and that the areas most
sensitive to acid rain were the Adirondacks, the mid-Appalachian highlands, the upper Midwest and the high elevation West. The NSWS found that approximately 580 streams in the
Mid-Atlantic Coastal Plain are acidic primarily due to acidic deposition.
Hundreds of the lakes in the Adirondacks surveyed in the NSWS have acidity levels incompatible with the survival of sensitive fish species. Many of the over 1,350 acidic streamsin the Mid-Atlantic Highlands (midAppalachia) region have already experienced trout losses due to increased stream acidity. Emissions
from U.S. sources contribute to acidic deposition in eastern Canada, where the Canadian government has estimated that 14,000 lakes are acidic. Acid deposition also has been implicated in contributing to degradation of high-elevation spruce forests that populate the ridges of the Appalachian Mountains from Maine to Georgia. This area includes national parks such as the Shenandoah and Great Smoky Mountain National Parks.

The SO X and NO X reductions from today’s actions will help reduce acid rain and acid deposition, thereby helping to reduce acidity levels in lakes and streams throughout the U.S. These reductions will help accelerate the recovery of acidified lakes and streams and the revival of ecosystems adversely affected by acid deposition. Reduced acid deposition levels will also help reduce stress on forests, thereby accelerating reforestation efforts and improving timber production. Deterioration of our historic buildings and monuments, and of buildings, vehicles, and other structures exposed to acid rain and dry acid deposition, also will be reduced, and the costs borne to prevent acid-related damage may also decline.

While the reduction in sulfur and nitrogen acid deposition will be roughly proportional to the reduction in SOX and NO X emissions, respectively, the precise impact of today’s vehicle and
fuel standards will differ across different areas. Each area is affected by emissions from different source regions,
and the mobile source contribution to
the total SO X and NO X emission inventory will differ across different source regions. Nonetheless, the projected impact of today’s actions on

SO X and NO X emission inventories provides a rough indicator of the likely
effect of the Tier 2/Gasoline Sulfur standards on acid deposition. Our analysis indicates that today’s actions
will reduce SO X emissions by 1.8 percent and NO X emissions by 14.5 percent in 2030.

The analysis of economic benefits and
costs found in Section IV.D.5. did not
account for the economic benefits of the reduction in acid deposition expected to result from today’s actions.

H. Eutrophication/Nitrification

Nitrogen deposition into bodies of water can cause problems beyond those
associated with acid rain. The Ecological Society of America has
included discussion of the contribution of air emissions to increasing nitrogen
levels in surface waters in a recent major review of causes and consequences of human alteration of the global nitrogen cycle in its Issues in Ecology series 41 . Long-term monitoring in the United States, Europe, and other developed regions of the world shows a substantial rise of nitrogen levels in surface waters, which are highly correlated with human-generated inputs of nitrogen to their watersheds. These nitrogen inputs are dominated by fertilizers and atmospheric deposition.

Human activity can increase the flow
of nutrients into those waters and result in excess algae and plant growth. This increased growth can cause numerous adverse ecological effects and economic impacts, including nuisance algal blooms, dieback of underwater plants due to reduced light penetration, and toxic plankton blooms. Algal and plankton blooms can also reduce the level of dissolved oxygen, which can also adversely affect fish and shellfish populations. This problem is of particular concern in coastal areas with poor or stratified circulation patterns, such as the Chesapeake Bay, Long Island Sound, or the Gulf of Mexico. In such areas, the ‘‘overproduced’’ algae tends to sink to the bottom and decay, using all or most of the available oxygen and thereby reducing or eliminating populations of bottom-feeder fish and shellfish, distorting the normal population balance between different aquatic organisms, and in extreme cases causing dramatic fish kills.

Collectively, these effects are referred to as eutrophication, which the National Research Council recently identified as the most serious pollution problem facing the estuarine waters of the United States (NRC, 1993). Nitrogen is the primary cause of eutrophication in most
coastal waters and estuaries 42 . On the New England coast, for example, the
number of red and brown tides and shellfish problems from nuisance and toxic plankton blooms have increased over the past two decades, a development thought to be linked to increased nitrogen loadings in coastal
waters. Airborne NO X contributes from 12 to 44 percent of the total nitrogen loadings to United States coastal water bodies. For example, approximately one-quarter of the nitrogen in the Chesapeake Bay comes from atmospheric deposition.

Excessive fertilization with nitrogencontaining compounds can also affect terrestrial ecosystems 43 . Research suggests that nitrogen fertilization can alter growth patterns and change the


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balance of species in an ecosystem. In extreme cases, this process can result in nitrogen saturation when additions of nitrogen to soil over time exceed the capacity of the plants and microorganisms to utilize and retain the nitrogen. This phenomenon has already
occurred in some areas of the U.S.

Deposition of nitrogen from cars and light trucks contributes to these problems. As discussed in Section III.B. above, today’s actions will reduce total

NO X emissions by 4.5 percent in 2007 and by 14.5 percent in 2030. The NOX reductions should reduce the eutrophication problems associated with atmospheric deposition of nitrogen
into watersheds and onto bodies of water, particularly in aquatic systems where atmospheric deposition of nitrogen represents a significant portion of total nitrogen loadings. Since air deposition accounts for 12–44 percent of total nitrogen loadings in coastal waters, the reduction in NO X from today’s actions is projected to reduce nitrogen loadings by 0.5–2.0 percent in 2007 and 1.7–6.4 percent in 2030. To put these reductions in perspective, the reductions expected in the Chesapeake Bay area would amount to about 9 percent of the total reduction in nitrogen loading needed to maintain the reduction in nutrient loads agreed to by the signatory states in the Chesapeake Bay Agreement (40 percent of ‘‘controllable nutrient loads’’ by the year 2000).

The analysis of economic benefits and
costs found in Section IV.D.5. does not
account for the economic benefits of reduced eutrophication or reduced terrestrial nitrogen deposition expected to result from today’s actions.

I. Cleaner Cars and Light Trucks Are Critically Important to Improving Air Quality

Despite continued progress in reducing ozone and PM levels, tens of millions of Americans are still exposed to levels of these pollutants that exceed the National Ambient Air Quality Standards. Our projections show that
without further action to reduce these pollutants, tens of millions of
Americans will continue to breathe unhealthy air for decades to come. Our projections also show that emissions from cars and light trucks will continue
to contribute a substantial share of the ozone and PM precursors in current and projected nonattainment areas, and in upwind areas whose emissions contribute to downwind nonattainment,
unless additional measures are taken to reduce their emissions. Cars and light trucks also contribute substantially to
ambient concentrations of CO. These vehicles will also continue to contribute to the ambient PM that affects visibility
in Class I federal areas and some urban areas. Emissions from cars and light trucks also play a significant role in a wide range of health and environmental problems, including known and potential cancer risks from inhalation of air pollutants (a problem that could become more significant if sales of diesel-powered cars and light trucks were to increase), health risks from elevated drinking water nitrate levels, acidification of lakes and streams, and eutrophication of inland and coastal

waters.

Today’s actions will reduce NO X , VOC, CO, PM, and SO X emissions from these vehicles substantially. These reductions will help reduce ozone levels
nationwide and reduce the extent and severity of violations of the 1-hour
ozone standard. These reductions will also help reduce PM levels, both by reducing direct PM emissions and by reducing emissions that give rise to secondary PM. The CO reductions will help extend the downward trend in carbon monoxide levels, thereby helping the remaining CO
nonattainment areas attain the CO standard and helping other areas stay in attainment with the CO standard despite
continued increases in vehicle miles
traveled. The NO X and SO X reductions will help reduce acidification problems,
and the NO X reductions will help reduce eutrophication problems and drinking water nitrate levels. The PM standards included in today’s actions will help improve visibility and would help mitigate adverse health effects in the event of increases in light-duty diesel engine sales.

IV. What Are the New Requirements for
Vehicles and Gasoline?

A. Why Are We Proposing Vehicle and Fuel Standards Together?

1. Feasibility of Stringent Standards for Light-Duty Vehicles and Light-Duty
Trucks.

a. Gasoline Fueled Vehicles

We believe that the standards being promulgated today for gasoline-fueled
vehicles are well within the reach of existing control technology. Our determination of feasibility is based on the use of catalyst-based strategies that are already in use and are well proven on the existing fleet of vehicles. In fact, as you will see below, many current engine families are already certified to
levels at or below the new final Tier 2 requirements. All of the certification and research testing discussed below was performed on low-sulfur test fuel (nominally 30 ppm).

i. LDVs and LDT1s–LDT4s

Certainly, larger vehicles and trucks, which are heavier and have larger frontal areas, will face the biggest challenges in meeting the final Tier 2 standards. However, conventional technology will be sufficient for even these vehicles, especially in light of the extra leadtime we have provided before
LDT3s and LDT4s have to meet Tier 2 levels. We are also changing the test
conditions for these trucks from ‘‘adjusted loaded vehicle weight’’ to ‘‘loaded vehicle weight.’’ Adjusted loaded vehicle weight, suitable for commercial truck operation, loads the truck to half of its full payload. Loaded vehicle weight, on the other hand, represents curb weight plus 300 pounds. This change more accurately reflects
how these vehicles are used and makes heavy LDT testing consistent with passenger car and light LDT testing. This change is consistent with treating these vehicles as they were designed,
i.e., for light-load use.

Emission control technology has evolved rapidly in recent years. Emission standards applicable to 1990 model year vehicles required roughly 90 percent reductions in exhaust HC and CO emissions and a 75 percent
reduction in NO X emissions compared to uncontrolled emissions. Today, some vehicles currently in production are well below these levels, showing even greater overall emissions reductions of all three of these pollutants. These
vehicles’ emissions are well below those necessary to meet the current federal
Tier 1 and even California LowEmission Vehicle (LEV–I) standards. The reductions have been brought aboutby ongoing improvements in engine airfuel management hardware and software plus improvements in catalyst designs, all of which are described fully in the

RIA.

The types of changes being seen on current vehicles have not yet reached their technological limits, and continuing improvement will allow
both LDVs and LDTs to meet the final standards. The RIA describes a range of specific techniques that we believe could be used. These range from improved computer software and engine air-fuel controls to increases in precious metal loading and other exhaust system/ catalyst system improvements. All of these technologies are currently used on one or more production vehicle models.
There is no need to invent new approaches or technologies. The focus of the effort is primarily development,


### 6725 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

44 Powertrain control modules are computers used to control engine, transmission, and other
vehicle functions on newer automobiles and trucks. The changes involved software changes in the case of the EPA-NVFEL work, or the use of alternate means of engine control in the case of the SwRI

work.

45 Although this testing was done on vehicles with catalysts aged to 50,000, we belive the overall experiments also strongly suggest that the Tier 2full-life standards would be achieved by highmileage vehicles. application, and optimization of these existing technologies.

We can gain significant insight into the difficulty of meeting the final new standards by looking at current full-life
certification data. There are at least 48 engine family-control systems combinations, out of approximately 400,
certified in 1999 at levels below the Tier

2 NO X standard of 0.07 g/mi. Of these, 35 also have hydrocarbon levels of 0.09 g/mi or below. Looking at a somewhat higher threshold to identify vehicles certified near the final standard, there are an additional 113 car and light truck
families certified at levels between 0.07 g/mi and 0.10 g/mi NO X . Although not yet complete at this time, we also examined the 2000 model year
certification data and found that there are at least 60 engine family-control systems combinations certified at levels
below the Tier 2 NO X standard of 0.07 g/mi and of those, 52 also have hydrocarbon levels of 0.09 g/mi or
below.

All of the above vehicles are already able, or close to being able, to certify to
our final standards. The further reductions needed are those to provide a compliance margin, or cushion,
between the certified level and the emission standard. The degree of compliance margin required is a function of a variety of factors designed to provide the manufacturer a high confidence that production vehicles will
meet the standards in-use over their useful life. Historically, these
determinations are manufacturer specific, with cushions generally growing smaller as standards decline (reflecting more precision and repeatability in vehicle performance as more sophisticated controls are developed). The certification data reflects compliance cushions from as little as 20 percent below the standard to as high as 80 percent below the
standard.

The manufacturers commented that the most difficult vehicles to bring into compliance with the Tier 2 standards would be the larger light-duty trucks, specifically those trucks currently
certified under the LDT3 and LDT4 weight categories. Because of this, we undertook a technology demonstration program aimed at lowering theemissions of several large 1999 lightduty trucks. Two LDT3 Chevrolet Silverado pick-up trucks were tested, one internally and one under contract. Two LDT4 Ford Expedition sport-utility vehicles were also tested, also with one tested internally and one under contract. Both types of vehicles were tested with optional high horsepower engines (270 hp for the Silverado and 230 hp for the Expedition) and were equipped with four-wheel drive. The vehicles had curb weights of 4,500 pounds (GVWR of 6,100 lbs) for the Silverados and 5,800 pounds (GVWR of 7,200 lbs) for the Expeditions.

Figures IV.A.–1 and IV.A.–2 show the
results to date of the emissions tests performed during this demonstration program at our National Vehicle and Fuel Emissions Laboratory (NVFEL) and
also for emissions tests conducted in parallel by and under contract at Southwest Research Institute (SwRI) using similar Ford Expeditions and GM Chevrolet Silverados. During the evaluation, the trucks were equipped with a variety of catalysts that typically featured higher volume, higher precious metal loading, and higher cell-densities than the original hardware used by the
vehicles to meet California LEV–I standards. Details of the catalysts tested
are included in the RIA. Different exhaust manifolds featuring an insulating air-gap and low thermal mass were also evaluated. Finally, calibration changes were made to the powertrain
control modules 44 to better match engine operating characteristics to the new catalyst systems, and to lower engine-out NOx emissions. The Silverado and Expedition had very
similar results. Similar results were also achieved by us and SwRI, but by fairly
different methods. The SwRI work on both trucks relied primarily on engine calibration changes and secondary air injection. The advanced catalyst systems used by SwRI contained
advanced washcoat formulations with only minor changes to catalyst volume and precious metal content compared to the manufacturer’s original configuration. The work we conducted on the Expedition also relied primarily on engine calibration changes with no secondary air injection. The catalyst system also contained advanced
washcoat formulations with modest changes to catalyst volume and precious metal content. The work we conducted on the Silverado relied primarily on an advanced catalyst system with volume and precious metal content changes, with only minor changes to engine
calibration.

As can be seen in the charts, the emissions of the vehicles tested clearly show the feasibility of the Tier 2 standards on the most difficult to certify vehicle categories. All vehicles reached
emission levels well below the Tier 2
full-life NOx and NMOG standards. At the same time, there were no significant impacts on either fuel economy or performance of the vehicles.

Compared to the intermediate (50,000 mile) standards, the Ford Expedition tested at NVFEL consistently emitted
NOx at less than one-third of the
intermediate useful life standard. 45 NMHC/NMOG emissions were slightly
below the intermediate standard level with no use of secondary-air-injection for cold-start hydrocarbon control. The
Silverado tested at NVFEL met the intermediate standards with primarily hardware (catalyst) changes and only very minor calibration changes. The
trucks tested at SwRI differed from
those tested at NVFEL in their
combination of emissions control hardware and calibration strategies, but achieved approximately the same
emissions levels.

The above results point out that not only are the Tier 2 standards feasible for larger trucks, but there are multiple
means that can be taken in order to achieve the necessary emissions levels. All of those paths involve fairly simple enhancements to current technology systems. Furthermore, the testing was conducted with a very limited budget
over a limited amount of time. With the interim program for heavy trucks under Tier 2, the manufacturers will have 9 years from the publishing of the Tier 2 rule to bring the largest trucks into compliance with the Tier 2 standards.
Manufacturers will also have considerably more resources with respect to calibration changes and hardware design to bring trucks of this type within compliance than were available within this limited, but successful, demonstration.

BILLING CODE 6560–50–P


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BILLING CODE 6560–50–C

The Manufacturers of Emission Controls Association (MECA) sponsored a program that took two LDVs (a Crown Victoria and a Buick LeSabre) and one LDT2 (a Toyota T100) certified to the federal Tier 1 standards and replaced the original catalytic converter systems with more advanced catalytic converters, thermally aged to approximately 50,000 miles. With these systems and some related emission control modifications, the LeSabre and
T100 emissions were well below our intermediate (50,000 mile) useful life standards, and the Crown Victoria was
well below the NMOG standard and very close to the NO X standard.

Finally, the California Air Resources Board (ARB) tested five different production LEV light-duty vehicle
models. Three of the five models met
the Tier 2 standards for NMOG and NOX prior to any modifications. After installing low mileage advanced catalytic converters and making some minor adjustments to fuel bias, air injection, and spark timing, all of the
vehicles had emission levels well below
the Tier 2 intermediate useful life
NMOG and NO X standards. ARB also tested several Ford Expeditions (LDT4) equipped with advanced catalytic converters. By adjusting several parameters, they were able to reduce

NO X emissions to 0.06 g/mi and NMOG to 0.07 g/mi with a catalyst aged to 50,000 miles of use.

A more expanded analysis of the feasibility of the Tier 2 standards for gasoline fueled vehicles can be found in the RIA, considering the types of changes that will allow manufacturers
to extend effective new controls to the
entire fleet of affected vehicles. That analysis includes discussion of gasoline direct-injection engines, as well as the feasibility of the CO, formaldehyde and evaporative emission standards. The conclusion of all of our analyses is thatthe standards are feasible for gasolinefueled vehicles. As gasoline-fueled vehicles represent the overwhelming majority of the LDV and LDT population (i.e., over 99%), EPA concludes that the
Tier 2 standards are feasible overall for
LDVs and LDTs under 8500 lbs GVWR.

ii. Medium-Duty Passenger Vehicles (MDPVs)

The technologies and emission control strategies that will be used for LDT3 and LDT4 vehicles with a GVWR less than 8,500 pounds should apply directly to MDPV vehicles that have a GVWR greater than 8,500 pounds. In our LDT technology demonstration program discussed above, we found that a combination of calibration changes and improvements to the catalyst system
resulted in emission levels for NOX well
below and NMHC/NMOG approximately at the Tier 2 intermediate useful life standards. The catalyst improvements consisted of increases in volume and precious metal loading, and higher cell-densities than those found in the original hardware. We are confident that the use of secondary-air-injection will greatly help cold-start hydrocarbon control, making the NMOG standards
achievable.

The most significant difference between LDT4s less than 8,500 pounds GVWR and MDPVs greater than 8,500 pounds GVWR is that MDPVs have a vehicle weight up to 800 pounds more
than LDT4s. MDPVs will also be typically equipped with larger displacement engines. The potential impact of these differences is higher engine-out emissions than LDT4s due to the larger engine displacement and


### 6728 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

46 ‘‘Cummins Sees Diesel Feasible for Early Years of Tier 2’’. Hart Diesel Fuel News, Sept. 20, 1999,
p.2. 47 Harts Diesel Fuel News, August 9, 1999, p4. greater load that the engine will be operated under due to the extra weight. However, neither of these preclude manufacturers from applying the same basic emission control technologies and strategies as used by LDVs and LDTs. The only difference will likely be the need for larger catalysts with higher precious metal loading than found in
LDT4s. We are confident that MDPVs will be capable of meeting the final Tier
2 standards.

We are currently testing a Ford Excursion as part of our LDT technology demonstration program. Preliminary baseline results with a ‘green’’ (i.e., nearly new) catalyst indicate that emission levels are higher than baseline emissions for the Ford Expedition. These results, although with a green catalyst, are well below our interim Tier 2 upper bin standards. In fact, the majority of these vehicles certified on the chassis dynamometer in California
have certification levels well below our interim upper bin standards. While this testing is ongoing, we feel that the preliminary results are encouraging since they suggest that the difference in
emissions between the Excursion and Expedition suggest that the strategies used on the Expedition can be
successful with the Excursion. Therefore, we believe that by using technologies and control strategies similar to what will be used by LDVs and LDTs, combined with larger catalysts, MDPVs will be able to meet
our Tier 2 emission standards.

b. Diesel Vehicles

As discussed above, the Tier 2
standards are intended to be ‘‘fuel neutral.’’ In today’s document, we
establish that the Tier 2 standards aretechnologically feasible and costeffective for LDVs and LDTs overall,
based on the discussion in Section IV.A.1.a. above. Under the principle of fuel neutrality, all cars and light trucks, including those using diesel engines, will be required to meet the Tier 2 standards. Contrary to some of the comments received on our proposal, given that the overwhelming majority ofvehicles in these classes are gasolinefueled, we do not believe it is appropriate to provide less stringent
standards for diesel-fueled vehicles. Manufacturers of LDVs and LDTs today provide consumers with a wide choice of vehicles that are overwhelmingly gasoline-fueled. Less stringent standards for diesels would create provisions that
could undermine the emission reductions expected from this program, especially given the expectation that some manufacturers may intend to greatly increase their diesel sales. As with gasoline engines,
manufacturers of diesels have made abundant progress over the past 10 years in reducing engine-out emissions from diesel engines. In heavy trucks and buses, PM emission standards, which were projected to require the use of exhaust aftertreatment devices, were actually met with only engine modifications. Indeed, emissions and performance of lighter diesel engine are rapidly approaching the characteristics of gasoline engines, while retaining the durability and fuel economy advantages that diesels enjoy. Against this background of continuing progress, we believe that the technological improvements that would be needed
could be made in the time that would
be available before diesels would have
to meet the new Tier 2 standards.

Manufacturers may take advantage of the flexibilities in today’s rulemaking to delay the need for diesel LDVs and
LDTs to meet the final Tier 2 levels until late in the phase-in period (as late as
2007 for LDVs/LLDTs and 2009 for HLDTs), giving manufacturers a relatively large amount of leadtime. In a recent public statement, Cummins Engine Company has indicated that the
interim Tier 2 standards in effect for vehicles and trucks in the early years of the Tier 2 program are feasible for diesel equipped models through further development of currently available engine and exhaust aftertreatment technology. 46

While reductions in ‘‘engine-out’’ emissions, including incorporation of EGR strategies, may continue to be made, increasing emphasis is being placed on various aftertreatment devices
for diesels. We believe that the use of
aftertreatment devices will allow diesels to comply with the Tier 2 standards for

NO X and PM.

For NO X emissions, potential aftertreatment technologies include lean

NO X catalysts, NO X adsorbers and selective catalytic reduction (SCR). Lean

NO X catalysts are still under development, but generally appear capable of reducing NO X emissions by about 15–30%. This efficiency is not likely to be sufficient to enable compliance with the final Tier 2 standards, but it could be used to meet the interim standards that would begin in 2004, with current diesel fuel.

NO X adsorbers appear capable of reaching efficiency levels as high as 90%. Efficiency in this range is likely to be sufficient to enable compliance with the proposed Tier 2 standards. NOX adsorbers temporarily store the NO X and thus the engine must be run periodically for a brief time with excess fuel, so that
the stored NO X can be released and converted to nitrogen and oxygen using a conventional three-way catalyst, like that used on current gasoline vehicles.

There is currently a substantial amount of development work being
directed at NO X adsorber technology.
While there are technical hurdles to be overcome, progress is continuing and it is our judgement that the technology should be available by the time it would
be needed for the final Tier 2 standards.

One serious concern with current

NO X adsorbers is that they are quickly poisoned by sulfur in the fuel. Some manufacturers have strongly emphasized their belief that, in order to meet the final Tier 2 levels, low sulfur diesel fuel would also be required to mitigate or prevent this poisoning problem. In its comments on the NPRM,
Navistar indicated that the Tier 2 standards may be achievable given low sulfur fuel and other programmatic changes such as those included in this
Final Rule. Navistar has also been quoted publically as describing the Tier 2 standards as ‘‘challenging but achievable’’ given appropriate low
sulfur fuel. 47 We intend to issue a Notice of Proposed Rulemaking early in the year 2000 intended to reduce sulfur in highway diesel fuel as a step to enable the technology most likely to be
used to meet the Tier 2 standards.

SCR has been demonstrated commercially on stationary diesel engines and can reduce NO X emissions by 80–90%. This efficiency would be sufficient to enable compliance with the proposed Tier 2 standards. However, SCR requires that the chemical urea be injected into the exhaust before the catalyst to assist in the destruction of

NO X . The urea must be injected at very precise rates, which is difficult to achieve with an on-highway engine, because of widely varying engine operating conditions. Otherwise, emissions of ammonia, which have a very objectionable odor, can occur.
Substantial amounts of urea are required, meaning that vehicle owners would have to replenish their vehicles’ supply of urea frequently, possibly as often as every fill-up of fuel. As the engine and vehicle would operate satisfactorily without the urea (only

NO X emissions would be affected), some
mechanism would be needed to ensure
that vehicle owners maintained their supply of urea. Otherwise, little NOX emission reduction would be expected

in-use.


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48 The air quality impacts discussed above under

Section III above do not reflect these new estimates. Regarding PM, applicable
aftertreatment devices tend to fall into two categories: Oxidation catalysts and traps. Diesel oxidation catalysts can reduce total PM emissions by roughly 15–30%. They would need to be used in conjunction with further reductions in PM engine-out emissions in order to meet the proposed Tier 2 standards. Diesel particulate traps, on the other hand, can eliminate up to 90% of diesel PM emissions. However, some of the means of accomplishing the regeneration of particulate traps involve catalytic processes that also convert
sulfur dioxide in the exhaust to sulfate. These techniques, if used, would also require a low sulfur fuel.

In summary, we believe that the structure of our final program, including the available bins and phase-in periods, will allow the orderly development of clean diesel engine technologies. We
believe that the interim standards are feasible for diesel LDV/LDTs, within the
bin structure of this rule and without
further reductions in diesel fuel sulfur levels. And, as indicated earlier, at least one major diesel engine manufacturer (Cummins) has publicly agreed with
this assessment. We further believe that in the long-term, the final standards will
be within reach for diesel-fueled
vehicles in combination with appropriate changes to diesel fuel to facilitate aftertreatment technologies. Manufacturers have argued that low sulfur diesel fuel will be required to permit diesels to meet the final Tier 2 standards, and we agree. At least one major manufacturer (Navistar) has
indicated its belief that the final Tier 2 standards may be achievable for diesel engines with low sulfur diesel fuel.

2. Gasoline Sulfur Control Is Needed to Support the Proposed Vehicle Standards

As we discussed in the previous section, we believe that the stringent
standards in this final rule are needed to meet air quality goals and are feasible for LDVs and LDTs. At the same time,
we believe that for these standards to be feasible for gasoline LDVs and LDTs, low sulfur gasoline must be made available. The following paragraphs explain why we think gasoline sulfur control must accompany Tier 2 vehicle
standards.

Catalyst manufacturers generally use low sulfur gasoline in the development of their catalyst designs. Vehicle manufacturers then equip their vehicles with these catalysts and EPA certifies them to the exhaust emission standards, usually based on testing the manufacturer does using low sulfur gasoline. However, fundamental chemical and physical characteristics of exhaust catalytic converter technology generally result in a significant degradation of emission performance when these vehicles use gasoline with
sulfur levels common in most of the country today. This sensitivity of catalytic converters to gasoline sulfur varies somewhat depending on a number of factors, some better understood than others. Clearly, however, as we discuss in the following paragraphs, gasoline sulfur’s impact is large, especially in vehicles designed to meet very low emission standards.

This is the reason EPA has decided to adopt a comprehensive approach to addressing emissions from cars and light trucks, including provisions to get low sulfur gasoline into the field in the
same time frame needed for Tier 2
vehicles.

a. How Does Gasoline Sulfur Affect
Vehicle Emission Performance?

We know that gasoline sulfur has a negative impact on vehicle emission controls. Vehicles depend on the catalytic converter to reduce emissions of HC, CO, and NO X . Sulfur and sulfur compounds attach or ‘‘adsorb’’ to the precious metal catalysts that are required to convert these emissions. Sulfur also blocks sites on the catalyst designed to store oxygen that are necessary to optimize NO X emissions
conversions. While the amount of sulfur contamination can vary depending on the metals used in the catalyst and other aspects of the design and operation of the vehicle, some level of sulfur contamination will occur in any catalyst.

Sulfur sensitivity is impacted not only by the catalyst formulation (the types and amounts of precious metals used in the catalyst) but also by factors including the following:

• The materials used to provide oxygen storage capacity in the catalyst, as well as the general design of the catalyst,

• The location of the catalyst relative to the engine, which impacts the temperatures inside the catalyst,

• The mix of air and fuel entering the engine over the course of operation, which is varied by the engine’s computer in response to the driving situation and affects the mix of gases entering the catalyst from the engine,
and

• The speeds the car is driven at and the load the vehicle is carrying, which also impact the temperatures experienced by the catalyst.

Since these factors vary for every vehicle, the sulfur impact varies for every vehicle to some degree. There is no single factor that guarantees that a vehicle will be very sensitive or very
insensitive to sulfur. We now believe that there are not (and will not be in the foreseeable future) emission control devices available for gasoline-powered vehicles that can meet the proposed Tier
2 emission standards that would not be significantly impaired by gasoline with sulfur levels common today.

b. How Large Is Gasoline Sulfur’s Effect

on Emissions?

High sulfur levels have been shown to significantly impair the emission control systems of cleaner, later technology vehicles. The California LEV standards and Federal NLEV standards,
as well as California’s new LEV–II standards and our Tier 2 standards, require catalysts to be extremely efficient to adequately reduce emissions
over the full useful life of the vehicle. In the NPRM we estimated that, based on data from test programs conducted by EPA and the automotive and oil industries, LEV and ULEV vehicles could experience, on average, a 40 percent increase in NMHC and 134 percent increase in NO X emissions when operated on 330 ppm sulfur fuel (our estimate in the NPRM of the current national average sulfur level) compared to 30 ppm sulfur fuel. New data generated since the NPRM on
similar LEVs and ULEVs show that
when these vehicles were driven on high sulfur (330 ppm) fuel for a few thousand miles (as opposed to less than 100 miles for the previous data), the
NMHC and NO X emission increase due to high sulfur fuel increased by 149 percent and 47 percent, respectively. In other words, instead of the previous estimated 40 percent and 134 percent
increases in NMHC and NO X emissions, respectively, more realistic estimates would be 100 percent and 197 percent, respectively. 48 Also, new data generated
since the NPRM for late model LEV and
ULEV vehicles that meet the federal and California supplemental federal test procedure (SFTP) standards and also have very low FTP emission levels, indicate that, on average, a 51 percent increase in NMHC and a 242 percent

increase in NO X emissions when operated for a short period of time on 330 ppm compared to 30 ppm could be
realized.

This level of emissions increase is significant enough on its own to cause
a vehicle to exceed the full useful life emission standards when operated on sulfur levels that are substantially higher than the levels required by today’s rule, even with the margin of


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safety that auto manufacturers generally include. Average sulfur levels in the U.S. are currently high enough to significantly impair the emissions control systems in new technology vehicles, and to potentially cause these
vehicles to fail emission standards required for vehicles up through 100,000 miles (or more) of operation.

For older vehicles designed to meet Tier 0 and Tier 1 emission standards,
the effect of sulfur contamination is somewhat less. Still, testing shows that gasoline sulfur increases emissions of
NMHC and NO X by almost 17% when one of these vehicles is operated on gasoline for less than 100 miles containing 330 ppm sulfur compared to operation on gasoline with 30 ppm sulfur. Thus, Tier 0 and Tier 1 vehicles can also have higher emissions when they are exposed to sulfur levels substantially higher than the proposed
sulfur standard. This increase is generally not enough to cause a vehicle
to exceed the full useful life emission standards in practice, but it can result
in in-use emissions increases since the vehicle could emit at levels higher than it would if it operated consistently on 30 ppm sulfur gasoline.

As discussed in the RIA, NLEV and Tier 2 vehicles are significantly more sensitive to sulfur poisoning than Tier 1 and Tier 0 vehicles. Because of this, even in the absence of Tier 2 standards, gasoline sulfur control to 30 ppm would achieve about 700,000 tons of NOX reductions per year from LDVs and LDTs by 2020. This represents about a
third of the national NO X emission
reductions otherwise available from these vehicles. Without these potential emission reductions, many states would face the potentially unmeetablechallenge of finding enough other costeffective sources of NO X emission
reductions to address their ozone
nonattainment and maintenance problems.

Sulfur reductions will result in reductions of other pollutants as well. For example, the increase in CO emissions at 330 ppm compared to 30 ppm were very similar to the results above for NMHC. Thus, sulfur reductions would greatly reduce CO emissions. Another example is sulfur reductions will help reduce emissions of particulate matter, providing some
benefit to PM nonattainment areas (which may or may not coincide with ozone nonattainment areas) as well as with visibility problems. Sulfur
reductions will also have benefits for areas across the country with acid deposition problems. Furthermore, sulfur reduction, by enabling tighter Tier 2 standards and by improving emissions performance of the vehicles already on the road, will lead to fewer NMOG emissions, since, as explained in the RIA, NMOG emissions are also impacted by gasoline sulfur (although to
a lesser extent than NO X emissions).
Some of the NMOG emissions reduced
are air toxics. As described in Section III above, air toxics, also known as hazardous air pollutants, or HAPs, contribute to a variety of human health problems.

c. Sulfur’s Negative Impact on Tier 2 Catalysts

As we discussed in the last section, sulfur contaminates the catalyst. In addition, essentially all vehicles that
have been tested show that this effect is
not reversible for one or more pollutants. The ability to reverse sulfur’s negative effect on catalyst performance is dependent on a number of factors. The same factors that impact sulfur sensitivity also impact the irreversibility of the sulfur effect. For example, the location of the catalyst relative to the engine, the materials used to provide oxygen storage capacity in the catalyst, and the general design of the catalyst and the mix of air and fuel (A/F) entering the engine over the course of operation affect irreversibility, to name
a few.

Perhaps the most significant factors for reversibility are the mixture of air and fuel entering the engine and catalyst temperature. The results of numerous studies and test programs show that rich exhaust (absence of oxygen) mixtures in addition to high catalyst temperatures (in excess of 700 ° C) can remove sulfur from the catalyst. Rich exhaust mixtures can occur intentionally and unintentionally, depending on the level of sophistication of the fuel control system. An intentional rich exhaust
mixture is known as fuel ‘‘enrichment.’’ There are different types of enrichment. For example, there is ‘‘commanded’’ enrichment, which is used to provide extra power when the engine is under a load ( e.g., accelerations), as well as a means to cool the catalyst. Also, there
is enrichment which results from the
normal fluctuations in A/F that occur during typical ‘‘closed-loop’’ FTP operating conditions. The amount of enrichment necessary for sulfur removal
is a function of several factors: the ‘‘magnitude’’ of the enrichment event, the duration of the enrichment event, and the frequency of which the
enrichment event occurs.

While the amount of fuel enrichment
is critical in the removal of sulfur from the catalyst, high catalyst temperature is equally as important. In order to meet strict Tier 2 standards, manufacturers are going to have to balance tight A/F control with improved catalyst performance, with an eye towards better catalyst thermal management. Many manufacturers are going to have to depend more on the precious metal palladium for oxidation of NMOG and CO emissions, as well as the reduction
of NO X , because palladium is more tolerant to high temperatures. Since the vast majority of emissions still occur immediately following a cold start when the catalyst is still cool, further
reductions to cold start emissions can be achieved by locating the catalysts very close to the engine. The closer proximity to the engine helps to activate the catalyst sooner by taking advantage of the additional heat supplied to the catalyst by the exhaust manifolds. Palladium is very sensitive to sulfur and, consequentially, catalyst systems that rely heavily on this metal tend to
be more sensitive to sulfur and less reversible. The precious metal platinum, although usually a little more effective at oxidizing NMOG and CO and slightly less sensitive to sulfur than palladium, is too sensitive to high temperature to survive the close proximity to the engine and is not anticipated to be used for close-coupled applications.

As discussed above, manufacturers
will need to make modifications to their emission system calibrations by optimizing fuel control, spark timing, EGR and other parameters in conjunction with improvements to catalyst systems, in order to meet Tier
2 emission standards. This combination of emission control strategies can result in significant trade-offs between NMOG
and NO X control. There can be considerable uncertainty associated with balancing these trade-offs at very
low emissions levels if the vehicle is periodically operated on high sulfur
fuels.

Our federal supplemental federal test procedure (SFTP) standards, as well as California’s SFTP standards, both of
which take effect in the 2001 model year, can further exacerbate this problem. The SFTP standards are
intended to better address and control emissions under driving conditions not captured when compliance with our
FTP-based exhaust emissions standards is demonstrated, such as operation with the air conditioning turned on or driving at very high rates of acceleration and vehicle speeds (hereafter referred to simply as aggressive driving). This is an important factor in assessing sulfur irreversibility, because Tier 2 vehicles will have to meet more stringent
exhaust emission standards and will
have to meet these standards over the wider variety of operating conditions


### 6731 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

49 The FTP (Federal Test Procedure) is the basic driving cycle used for federal emissions testing; the LA4 cycle is a component of the FTP. The REP05 cycle developed by EPA is representative of all driving that occurs outside the LA4 or FTP cycle. All but one of the aggressive accelerations found in the US06 cycle were taken from the REP05. While each segment of the US06 cycle was taken from actual in-use driving, the timing and combination of these segments is not representative of in-use driving in the way REP05 is representative. included in the SFTP provisions. Hence, they will have to be designed to meet
the emission standards under all such operating conditions; these design changes may influence how irreversible the sulfur effect will be, as explained
below.

Since wide variations in the A/F ratio help to remove sulfur from the catalytic surface, there is concern that vehicles which meet the SFTP standards, when driven aggressively, will experience insufficient enrichment to purge sulfur from the catalyst. Currently, when driven aggressively, the A/F ratio for most vehicles (those not certified to SFTP standards) is quite variable. Meeting the SFTP standards will ensure that manufacturers carefully control the A/F ratio over essentially all in-use driving conditions. This absence of widely varying A/F could therefore
inhibit the removal of sulfur from the catalyst once operation on high sulfur
fuel ceased.

In order to quantify how irreversible
the sulfur effect would be when catalysts exposed to high sulfur fuel are then exposed to lower sulfur fuel, several test programs were developed by EPA and industry. The vehicles in these test programs consisted of LDVs and
LDTs that met either EPA Tier 1 or
California LEV and ULEV emission
standards. All of the vehicles were first tested at a low sulfur level ( e.g., 30 or 40 ppm) to establish a baseline. The vehicles were then re-tested with high sulfur fuel ( e.g., 350 to 540 ppm). After emission results had stabilized, the vehicles were again re-tested with low
sulfur fuel. Prior to each of the second series of low sulfur tests, the vehicles were operated over a short driving cycle to help purge (i.e., remove) sulfur from the catalyst. Two different cycles were used to purge sulfur, representing different types of driving: moderate urban conditions and aggressive conditions. The FTP cycle, which represents moderate urban driving, and
the REP05 49 cycle, which represents very aggressive driving ( e.g., hard accelerations, high speed cruises), were the two cycles used.

The vehicles tested exhibited a wide range of irreversibility, for reasons that are not fully understood. The data published in the NPRM, showed that the effect of operation on high sulfur
fuel was irreversible on one or more pollutants after operation on low sulfur
fuel. NO X emissions were 15 percent
irreversible. None of the vehicles were designed or modified to meet either the
California or federal SFTP emissions standards. The only data used in an attempt to quantify the effect of aggressive operation on sulfur reversibility was from a catalyst manufacturer that performed some vehicle testing with catalysts which were bench aged with low and high sulfur fuel that appeared to closely approximate the impact aggressive operation would have on sulfur irreversibility. It was this data on which we based our projection of sulfur irreversibility for Tier 2 vehicles at 50 percent for NMHC and NO X emissions. Subsequent comments on the validity of these estimates after the publishing of the NPRM prompted several additional test programs on sulfur irreversibility.

The sulfur irreversibility test programs that followed the NPRM
focused on vehicles that had emission
levels that met or were close to Tier 2
emission standards and also met the US06 or aggressive driving portion of the SFTP emission standards. Although numerous vehicles were tested, only four met both of the above criteria. (We had tried to supplement the data base, but we were only able to add a limited number of vehicles.) We also decided to quantify irreversibility for NMHC and

NO X emissions together instead of independently, because per our discussion above, sensitivity and irreversibility of either pollutant appears to be very dependent on the particular strategy chosen to reduce these emissions (particularly engine calibration and catalyst loading of precious metals and oxygen storage).

The new data exhibited a range of variability among vehicles and pollutants, similar to the data presented in the NPRM. The most important
distinction between the new FRM data
and the old NPRM data was that the new data showed that, on average,

NMHC+NO X emissions in three out of four vehicles were not fully reversible after aggressive driving. Based on this data, we project that NMHC+NO X emissions will be 20 to 65 percent
irreversible for Tier 2 vehicles under typical in-use driving, including aggressive driving.

As discussed above, the combination of calibration changes and emission system hardware modifications needed to meet our stringent Tier 2 emissions standards, can result in significant
trade-offs between NMHC/NMOG and

NO X control. There can be considerable uncertainty associated with balancing these trade-offs at very low emissions levels if the vehicle is periodically operated on high sulfur fuels, making the ability to remove sulfur from the catalyst highly uncertain. For example, a given catalyst today may be fully reversible for one pollutant and only partially reversible for another. However, because of the trade-off in
NMOG and NO X performance, the modifications necessary to get that
vehicle to meet both emission standards may result in the opposite effect for reversibility; i.e., full reversibility for NMOG and partial reversibility for NOX
. There is no technical certainty that both
the NMOG and NO X emission standards can be met without compromising reversibility performance. Therefore, we continue to believe that sulfur’s negative impact on Tier 2 catalysts is a
substantial concern.

The preceding discussion focused on the irreversibility of the sulfur impact on emissions from current gasoline engine technologies. There are new technologies under development, which
could be sold in the U.S. in the middle of the next decade (the same time that Tier 2 vehicles are being introduced), which also appear to be very sensitive to sulfur and largely unable to reverse this sulfur impact. One of these technologies is the direct injection gasoline (GDI) engine. These engines
utilize much more air than is needed to burn the fuel, unlike conventional gasoline engines that operate under conditions where only just enough air to completely burn the fuel is introduced into the engine. This GDI technology allows these engines to be up to 25% more fuel efficient than current gasoline engines and to emit up to 20% less carbon dioxide. GDI engines are currently being introduced in both Japan and Europe (which have or will soon require low sulfur gasolines). Because of the significant operating differences with GDI engines, these vehicles will likely require emission control technology substantially
different from that used on conventional gasoline engines. For example, a GDI engine may require a NO X adsorber to meet the proposed Tier 2 NOX standard. High fuel sulfur levels quickly and permanently degrade the performance of
these NO X adsorbers. Thus, to enable the sale of advanced, high efficiency GDI engines in the U.S. under the Tier 2 standards, it appears that low sulfur gasoline would have to be available nationwide by the time this technology
becomes available.

The fuel cell is another promising propulsion system that is being developed for possible introduction to


### 6732 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

50 U.S. EPA, ‘‘OBD & Sulfur Status Report: Sulfur’s Effect on the OBD Catalyst Monitor on Low Emission Vehicles,’’ March 1997, updated September 1997. 51 In this section and also in section V, we make various references to the Tier 2 program, the interim program (or standards) and the final Tier 2 standards. The Tier 2 program includes the interim program (or standards) and the final Tier 2 standards. Some discussion is applicable to the entire Tier 2 program, some to the interim program (or standards) only and some is only applicable to the final Tier 2 standards. As the program is complex, we advise you to read carefully to discern the applicability of the text to the proper model years and categories of vehicles. consumers early in the next century. Fuel cells are being designed to operate on a variety of fuels, including gasoline
and diesel fuel. The basic fuel cell technology is highly sensitive to sulfur. Almost any level of sulfur in the fuel will disable the fuel cell. One possible solution is to install a technology that essentially filters out the sulfur before it enters the fuel cell. However, such sulfur ‘‘guards’’ are costly and could not practically be used like a disposable filter (requiring the vehicle owner to change the sulfur guard frequently, much like changing an oil filter) in situations where constant exposure to high sulfur levels occurs. (Even exposure to relatively low sulfur levels will likely require periodic replacement of the sulfur guard to ensure adequate protection for the fuel cell.) Therefore,
the amount of sulfur in the fuel must be limited to that which can be removed by one or at most two sulfur guards over the life of the vehicle. Thus, in order for fuel cells operating on gasoline to be feasible in the U.S., low sulfur fuels
would have to be available nationwide by the time this technology becomes
available.

d. Sulfur Has Negative Impacts on OBD Systems

As discussed in more detail in the RIA, EPA believes that sulfur in gasoline can adversely impact the onboard diagnostic (OBD) systems of current vehicles as well as vehicles meeting the Tier 2 standards. This is an important factor supporting the need for a national sulfur control program. EPA’s onboard diagnostics (OBD) regulations require that all vehicles be equipped with a system that monitors, among other things, the performance of the catalyst and warns the owner if the catalyst is not functioning properly. The OBD catalyst monitor is designed to identify those catalysts with pollutant
conversion efficiencies that have been reduced to the extent that tailpipe emissions would exceed a specified multiple of the applicable hydrocarbon
emissions standard. For California LEV and federal NLEV vehicles, that multiple is 1.75 times the applicable hydrocarbon emissions standard; for federal Tier 1 vehicles, that multiple is 1.5 times the applicable hydrocarbon standard added to the 4,000 mile
emission level.

We want to ensure that OBD systems operate correctly, and thus the possibility that gasoline sulfur may interfere with these systems was another consideration when evaluating the need for a national sulfur program. Our
evaluation of sulfur’s effect on OBD systems was summarized in a staff paper in 1997. 50 We concluded that sulfur can affect the decisions made by the OBD systems. Sulfur appears to affect the oxygen sensor downstream of the catalyst, which is used in the OBD systems, and it is not clear that the
conditions that seem to reverse sulfur’s effect on the catalyst will also reverse any sulfur impact on the downstream oxygen sensors. Indirectly, sulfur impacts OBD systems because it can impair a catalyst that would otherwise be operating satisfactorily, thereby triggering the OBD warning lights. While this would indicate a properly operating OBD system, auto manufacturers have expressed the concern that consumers using high sulfur fuel may experience OBD warnings much more frequently than they would if operating on low sulfur gasoline, and that this could lead to a
loss of consumer confidence in or support for OBD systems. Consumers may then ignore the OBD warning system and drive a potentially high emitting vehicle (which may have nothing to do with exposure to sulfur), contributing even more to air quality problems. Another possible scenario is that the OBD system may be impaired by sulfur in such a way that it does not register an improperly functioning catalyst, even if the catalyst is impaired for reasons unrelated to exposure to sulfur. This would defeat the purpose of OBD systems.

The reduction of sulfur levels for gasoline should resolve any concerns over the ability of the OBD system to make proper decisions. The use of low
sulfur fuel should ensure that the OBD warning light goes on when it is supposed to and is not influenced by sulfur contamination of the catalyst and/or OBD system.

B. Our Program for Vehicles

The program we are establishing today for cars, light trucks, and large passenger vehicles will achieve the same large NO X reductions that we projected for the proposed program. The program is very similar to our proposed program in all major respects. We have been able to retain the general structure, stringency, and emissions benefits of the proposal in this final rule. Where we have made adjustments to the proposed program, we have done so in ways that improve the implementation of the program without changing the overall environmental benefits that the program will achieve. And by creating a new category of vehicles subject to the Tier 2 standards, medium-duty passenger vehicles, the final rule will ensure that all passenger vehicles expected to be on
the road in the foreseeable future will be very clean.

We have seriously considered the input of all stakeholders in developing our final rule and believe the program
finalized below balances the concerns of all stakeholders while achieving the needed air quality benefits. In general, the adjustments we have made are aimed at improving the implementation efficiency of the program by better aligning the federal Tier 2 program with the NLEV program and with California’s program especially during the interim

program. 51 Extensive comments from
manufacturers led us to conclude that better harmony between the two programs would reduce the engineering, testing and certification workload related to our interim program. Where we could make changes to increase the overlap of the two programs while maintaining the NO X reductions of the proposal, we have done so. These changes are discussed in detail in this
section IV.B. and in sections V.A. and

V.B.

Our final rule also includesprovisions to regulate complete heavyduty passenger vehicles (primarily SUVs and passenger vans) of less than 10,000 pounds GVWR within the Tier 2 program. Standards for these vehicles were not included in the Tier 2 NPRM, but were proposed in a subsequent NPRM on October 29, 1999 (64 FR 58472). The final provisions for these
vehicles are addressed in section IV.B.4.g. These heavier vehicles have been recategorized as medium duty passenger vehicles (MDPVs). They are included in the Tier 2 program starting with model year 2004 and will be treated similarly to HLDTs, unless
otherwise noted.

The next sections of the preamble describe our final program in detail and include changes and adjustments from the NPRM that we believe address many concerns raised by the Alliance and others. While these changes ease the burden on manufacturers, they have little or no impact on the air quality benefits of the Tier 2 program.


### 6733 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

52 The NLEV program is a voluntary program, adopted by all major LDV and LDT manufacturers. It applies only to LDVs, LDT1s and LDT2s. It does not apply to HLDTs. 53 Throughout this text, the term ‘‘full life’’ is

used in reference to vehicle standards to mean ‘‘full useful life’’ which is currently 10 years/100,000 miles for LDVs and LLDTs, but 11 years/120,000 miles for HLDTs. Similarly, ‘‘intermediate life’’

refers to intermediate useful life standards which apply for the period of 5 years/50,000 miles. In this rulemaking we are retaining the current full useful life period for interim LDVs and LLDTs, but raising it for Tier 2 vehicles to 10 years/120,000 miles. In a number of places in the following text, we mention that changes are being made ‘‘in response to comments’’. For a full summary of the comments and for our responses to those comments, we refer you to the Response to Comments

document contained in the docket for this rulemaking or available from the Office of Mobile Sources web site (see web address at the beginning of this document).

1. Overview of the Vehicle Program

The vehicle-related part of today’s final rule covers a wide range of standards, concepts, and provisions that

affect how vehicle manufacturers will develop, certify, produce, and market

Tier 2 vehicles. This Overview subsection provides readers with abroad summary of the major vehiclerelated aspects of the rule. Readers for whom this Overview is sufficient may

want to move on to the discussion of the key gasoline sulfur control provisions (Section IV.C.). Readers wishing a more detailed understanding of the vehicle provisions can continue beyond the Overview to deeper discussions of key issues and provisions (Sections IV.B.–2, 3, and 4) as well as discussions of additional provisions (Section V.A.). Readers should refer to the regulatory language found at the end of this preamble for a complete compilation of the requirements.

To understand how the program will work, it is useful to review EPA’s classification system for light-duty vehicles and trucks. The light-duty category of motor vehicles includes all

vehicles and trucks at or below 8500 pounds gross vehicle weight rating, or GVWR (i.e., vehicle weight plus rated cargo capacity). Table IV.B.–1 shows the various light-duty categories and also shows our new medium-duty passenger vehicle (MDPV) category, discussed in section IV.B.4.g.. In the discussion below, we make frequent reference to two separate groups of light vehicles: (1) LDV/LLDTs, which include all LDVs and all LDT1s and LDT2s; and (2) HLDTs, which include LDT3s and

LDT4s. We also make mention of MDPVs although the details of our program for those vehicles are deferred to IV.B.4.g. at the end of section IV.B. 

### TABLE 

### IV.B.—1 L IGHT

### -D UTY 

### V EHICLES

AND 

### T RUCKS AND 

### M EDIUM 

### -D UTY 

### PASSENGER 

### V EHICLES 

### ; CATEGORY 

### C HARACTERISTICS

Characteristics

LDV .................... A passenger car or passenger car derivative seating 12 passengers

or less. Light LDT (LLDT) Any LDT rated at up through 6,000 lbs
GVWR. Includes LDT1

and LDT2. Heavy LDT

(HLDT). Any LDT rated at greater than 6,000 lbs GVWR.

Includes LDT3 and

LDT4s. MDPV ................. A heavy-duty passenger

vehicle rated at less than 10,000 lbs GVWR. (The inclusion of

MDPVs is discussed primarily in Section IV.B.4.g.)

a. Introduction

Today’s final rule incorporates concepts from the federal NLEV program which began phase-in in the 1999 model year for LDV/LLDTs. 52 The program in today’s rule takes the corporate averaging concept and other provisions from NLEV but changes the
focus from NMOG to NO X and applies
them to all LDVs and LDTs. The final rule is compatible with the California LEV II (CalLEV II) program scheduled to
take effect in 2004. The emission standard ‘‘bins’’ used for this average
calculation are different in several respects from those of the CalLEV II program, yet still allow harmonization
of federal and California vehicle technology.

The Tier 2 corporate average NOX level to be met through these requirements ultimately applies to all of
a manufacturer’s LDVs and LDTs (subject to two different phase-in schedules) regardless of the fuel used. Meanwhile, until the final Tier 2 standards are completely phased in, separate interim standards apply to
LDV/LLDTs and HLDTs.

As proposed in the NPRM and finalized in today’s document, the Tier 2 program will take effect in 2004, with full phase in occurring by 2007 for LDV/ LLDTs and 2009 for HLDTs. During the phase-in years of 2004–2008, vehicles not certified to Tier 2 requirements will meet interim requirements also using a bins system, but with less stringent corporate average NO X standards. In the discussions below, we set forth different Tier 2 phase-in schedules for the two different groups of vehicles (LDV/LLDTs and HLDTs) as well as two different interim fleet average NO X standards for 2004 and later model year vehicles awaiting phase-in to the Tier 2
standards.

In the NPRM, we set forth separate
tables of full life standard bins for the interim programs and the final Tier 2 program, but we proposed that
manufacturers could use all bins for interim or Tier 2 vehicles during the phase-in years. 53 We also proposed
similar sets of tables for intermediate life standards. In this final rule, for simplicity and to accommodate additional bins, including some suggested by the Alliance, we have
combined all of the full life bins into
one table and all of the intermediate life bins into one table. The bins system and
the choice of the individual bins is
discussed in detail below.

References to California LEV II Program

Throughout this preamble, we make reference to California’s LEV II program and its requirements. The LEV II program was approved by the California ARB at a hearing of November 5, 1998.
Numerous draft documents were prepared by ARB staff in advance of that hearing and made available to the public. Those documents were
referenced in our NPRM and included
in the docket. Some of those documents were modified as a result of changes to the proposed program made at the hearing and due to comments received after the hearing. ARB prepared final documents without significant change. The final program was approved by
California’s Office of Administrative Law on October 28, 1999 and filed with the Secretary of State to become effective on November 27, 1999.

We have placed copies of the latest available documents, some of which we used in the preparation of this final rule, in the docket. You may also obtain these
documents and other information about California’s LEV II program from ARB’s web site: (www.arb.ca.gov/regact/levii/ levii.htm).

In the regulatory text that follows this preamble, we incorporate by reference a
number of documents related to LEVII and California test procedures under


### 6734 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

54 These bins are unlikely to be used in the Federal program because they contain the same

NO X standard as the Federal bins, but contain more stringent NMOG standards than the Federal bins. These bins, which provide extra opportunity for a manufacturer to gain NMOG credits in California are not needed or useful in the Federal program where there is no NMOG corporate average

standard. The two deleted bins are bin 4 from the proposed Tier 2 bins and bin 3 from the proposed interim bins for LDV/LLDTs. Dropping these bins

does not affect harmonization with California standards because the federal program includes bins having the same NO X standard with higher

NMOG standards. LEVII. These documents are available in the docket for today’s rulemaking.

b. Corporate Average NO X Standard

The program we are finalizing today will ultimately require each manufacturer’s average full life NO X emissions over all of its Tier 2 vehicles

to meet a NO X standard of 0.07 g/mi each model year. Manufacturers will have the flexibility to certify Tier 2
vehicles to different sets of exhaust standards that we refer to as ‘‘bins,’’ but
will have to choose the bins so that their corporate sales weighted average full
life NO X level for their Tier 2 vehicles is no more than the 0.07 g/mi. (We discuss the bins in the next subsection.)

A corporate average standard enables the program’s air quality goals to be met while allowing manufacturers the flexibility to certify some models above
and some models below the standard. Manufacturers can apply technology to
different vehicles in a more costeffective manner than under a single set
of standards that all vehicles have to

meet.

Each manufacturer will determine its year-end corporate average NO X level by computing a sales-weighted average of
the full life NO X standards from the various bins to which it certified any
Tier 2 vehicles. The manufacturer will be in compliance with the standard if its corporate average NO X emissions for its
Tier 2 vehicles meets or falls below 0.07 g/mi. In years when a manufacturer’s corporate average is below 0.07 g/mi, it can generate credits. It can trade (sell)
those credits to other manufacturers or use them in years when its average exceeds the standard (i.e. when the manufacturer runs a deficit). The averaging program is described in detail
in later text.

c. Tier 2 Exhaust Emission Standard

‘‘Bins’’

We are finalizing a Tier 2 bin structure having eight emission standards bins (bins 1–8), each one a set
of standards to which manufacturers can certify their vehicles. Table IV.B.–2a
shows the full useful life standards that will apply for each bin in our final Tier 2 program, i.e. after full phase-in occurs
for all LDVs and LDTs. Two additional bins, bins 9 and 10, will be available only during the interim program and will be deleted before final phase-in of the Tier 2 program. Table IV.B.–2b
shows all the bins from Table IV.B.–2a and also shows extra bins and higher
available standards for certain pollutants that are available prior to full Tier 2 phase-in. An eleventh bin, only
for MDPVs is discussed in section IV.B.4.g.

Many bins have the same values as bins in the California LEV II program as
a means to increase the economic efficiency of the transition to as well as model availability. Further, we added bins that are not a part of the California program to modestly increase the flexibility of the program for manufacturers without compromising air quality goals. As discussed in Section IV.B.4. below, we believe these extra bins will help provide incentives for manufacturers to produce vehicles with emissions below 0.07 g/mi NOX
. The two highest of the ten bins shown in Table IV.B.2b. are designed to provide flexibility only during the phase-in years and will terminate after the standards are fully phased in, leaving eight bins in place for the duration of the Tier 2 program.

The NPRM full life standards
contained seven Tier 2 bins as well as two separate tables of bins for interim vehicles. We proposed that
manufacturers would be able to use all the bins during the phase in years regardless of whether they were certifying Tier 2 vehicles or interim
vehicles.

The program we are finalizing today:

• Combines the bins from the NPRM;

• Omits two bins that were included in the NPRM for harmony with California but which are unlikely to be used; 54 ;

• Adds 2 bins to increase compliance flexibility without reducing environmental benefits;

• Adds a temporary bin only for MDPVs that expires after 2008. This bin
is in addition to the 10 bins shown in tables of bins in this preamble;

• Establishes a PM value for the highest bin available during the interim program (bin 10) that is more stringent than the corresponding standard in the NLEV program;

• Provides temporary higher NMOG standards that expire after 2006 for
certain interim LDT2s and LDT4s produced by qualifying manufacturers.

Tables IV.B.–2a and 2b show the bins
for full life standards. Table IV.B.–2b is repeated later in the text where
intermediate life standards are also shown. These tables omit the temporary bin for MDPVs. This bin is usable only by MDPVs and is addressed separately in section IV.B.4.g.



### TABLE 

### IV.B.–2A 

### .—F INAL 

### T IER 

### 2 L IGHT

### -D UTY 

### F ULL 

### U SEFUL 

### L IFE 

### E XHAUST 

### E MISSION 

### STANDARDS

[Grams per mile]

Bin No. NOX NMOG CO HCHO PM

8 ............................................................................................................... 0.20 0.125 4.2 0.0 18 0.02

7 ............................................................................................................... 0.15 0.090 4.2 0.0 18 0.02

6 ............................................................................................................... 0.10 0.090 4.2 0.0 18 0.01

5 ............................................................................................................... 0.07 0.090 4.2 0.0 18 0.01

4 ............................................................................................................... 0.04 0.070 2.1 0.0 11 0.01

3 ............................................................................................................... 0.03 0.055 2.1 0.0 11 0.01

2 ............................................................................................................... 0.02 0.010 2.1 0.004 0.01

1 ............................................................................................................... 0.00 0.000 0.0 0.000 0.00


### 6735 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

55 In the NPRM, we proposed that hydrocarbon

standards would be measured in terms of ‘‘nonmethane organic gases’’ (NMOG) regardless of fuel. For reasons explained elsewhere in this preamble we will permit non-methane hydrocarbons (NMHC) as an option in the final rule for all fuels except alcohol fuels and compressed natural gas . NMHC and NMOG are very similar for gasoline and diesel

fuel emissions. 

### TABLE 

### IV.B.–2 B 

### .—T IER 

### 2 L IGHT

### -D UTY 

### F ULL 

### U SEFUL 

### L IFE 

### E XHAUST 

### E MISSION 

### STANDARDS

### —I NCLUDING 

### B INS 

### A PPLICABLE 

### D URING 

### I NTERIM 

### P ROGRAM 

### O NLY

[Grams per mile]

Bin No. NOX NMOG CO HCHO PM Comments

10 ................................................ 0.6 0.156/0.230 4.2/6.4 ......... 0.018/0.027 0.08 abcd
9 .................................................. 0.3 0.090/0.180 4.2 ............... 0.018 ........... 0.06 abc
8 .................................................. 0.20 0.125/0.156 4.2 ............... 0.018 ........... 0.02 b f

Notes:

a Bin deleted at end of 2006 model year (2008 for HLDTs).

b The higher of the two temporary NMOG, CO and HCHO values apply only to HLDTs.

c An additional higher temporary bin restricted to MDPVs is discussed in section IV.B.4.g.

d Optional temporary NMOG standard of 0.280 g/mi applies for qualifying LDT4s and MDPVs only, see text.

e Optional temporary NMOG standard of 0.130 g/mi applies for qualifying LDT2s only, see text.

f Higher temporary NMOG value of 0.156g/mi deleted at end of 2008 model year.

The corporate average concept using bins will provide a program that gets essentially the same emission reductions we would expect from a straight 0.07 g/mi standard for all
vehicles because all NO X emissions
from Tier 2 vehicles in bins above 0.07 g/mi will need to be offset by NOX emissions from Tier 2 vehicles in bins below 0.07 g/mile. This focus on NOX allows NMOG 55 emissions to ‘‘float’’ in
that the fleet NMOG emission rate depends on the mix of bins used to meet
the NO X standard. However, as you can see by examining the bins, any combination of vehicles meeting the 0.07 g/mi average NO X standard will have average NMOG levels below 0.09 g/mi. The actual value will vary by manufacturer depending on the sales
mix of the vehicles used to meet the 0.07 g/mi average NO X standard. In addition, there will be overall improvements in NMOG since Tier 2 incorporates HLDTs, which are not covered by the NLEV program. Tier 2 also imposes tighter standards on LDT2s than the NLEV program by making them average with the LDVs and LDT1s. NLEV has separate, higher standards for LDT2s. We did not adopt any bins for LDVs and LDTs with standards higher than we proposed.

d. Schedules for Implementation

We recognize that the Tier 2 standards pose greater technological challenges for larger light duty trucks ( HLDTs) than for LDVs and smaller trucks (LDT1s and LDT2s). We believe that additional leadtime is appropriate for HLDTs. HLDTs have historically been subject to less stringent vehicle-based standards than lighter trucks and LDVs. Also, HLDTs were not subject to the voluntary emission reductions implemented for LDVs, LDT1s and LDT2s in the NLEV program. Consequently we are finalizing as proposed, separate phase-in programsfor HLDTs and LDV/LLDTs . Our phasein approach will provide HLDTs with extra time before they need to begin phase-in to the final Tier 2 standards and will also provide two additional years for them to fully comply. Table IV.B–3 provides a graphical representation of how the phase-in of the Tier 2 program will work for all
vehicles. This table shows several aspects of the program:

• Phase-in of the Tier 2 standards;

• Phase-in/phase-out requirements of the interim programs;

• Phase-in requirements of new evaporative standards;

• Years that can be included in alternative phase-in schedules;

• Years in which manufacturers can
bank NO X credits through ‘‘early banking’’ and

• ‘‘Boundaries’’ on averaging sets in the Tier 2 and interim programs.

• Averaging provisions for MDPVs (see section IV.B.4.g. for discussion)

We discuss each of these topics in
detail below and make numerous
references to Table IV.B–3.

BILLING CODE 6560–50–P


### 6736 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

BILLING CODE 6560–50–C

As described in detail in the Response to Comments document, the Alliance proposal would have delayed final implementation of Tier 2 standards until 2011. We are not adopting the Alliance’s time schedule, because we
believe the shorter schedule we proposed is feasible and that there is no reason to delay the final benefits of the Tier 2 standards. In fact, numerous commenters representing state, environmental and health groups argued that our original proposal gave manufacturers too much time to bring

the HLDTs into line with LDVs and LLDTs. We believe the two extra years proposed in the NPRM remain appropriate. HLDTs will face greater challenges than LDVs/LLDTs because their emission control systems will need to be durable under potentially heavier loads and tougher operating conditions

than LDV/LLDTs. Their sales are small relative to the rest of the light duty fleet (they will comprise about 14% of the light duty fleet in 2004), and they will benefit from industry experience with the lighter vehicles. In addition, HLDTs will not remain at high Tier 1 levels until they phase-in to Tier 2. Rather, they will have to meet interim standards that impose a NO X cap of 0.60 g/mi and phase-in a corporate average NO X standard of 0.20 g/mi. These standards represent a significant reduction from


### 6737 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

56 Under Tier 1 standards, LDT3s are subject to a 0.98 g/mi NO X standard while LDT4s are subject to an even higher NO X standard of 1.53 g/mi. 57 The NLEV program imposes NMOG average

standards that translate into full useful life NO X levels of about 0.3 g/mi for LDV/LDT1s and 0.5 g/

mi for LDT2s. 58 The NLEV program does not impose average

NO X standards, but the NMOG average standards that it does impose will lead to full useful life NO X levels of about 0.3 g/mi for LDV/LDT1s. applicable Tier 1 standards. 56 Interim
standards are discussed in detail later in this preamble.

i. Implementation Schedule for Tier 2
LDVs and LLDTs

We are finalizing the implementation
schedule for the Tier 2 standards as proposed in the NPRM. Thus, the standards will take effect beginning with the 2004 model year for light duty
vehicles and trucks at or below 6000 pounds GVWR (LDV/LLDTs). Manufacturers will phase their vehicles into the Tier 2 standards beginning with 25 percent of LDV/LLDT sales that year, 50 percent in 2005, 75 percent in 2006, and 100 percent in 2007. Manufacturers
will be free to choose which vehicles are phased-in each year. However, in each year during (and after) the phase-in, the manufacturer’s average NO X for its Tier 2 vehicles must meet the 0.07 g/micorporate average standard. This phasein schedule, which is consistent with that of the California LEV II program, provides between four and seven years
of leadtime for the manufacturers to bring all of their LDV/LLDT production into compliance. These vehicles constitute about 86 percent of the light duty fleet.

To increase manufacturer flexibility and provide incentives for early introduction of Tier 2 vehicles, we are also finalizing provisions from the NPRM that permit manufacturers to use alternative phase-in schedules that will still require 100 percent phase-in by 2007, but recognize the benefits of early introduction of Tier 2 vehicles, and allow manufacturers to adjust their phase-in to better fit their own production plans. (See section IV.B.4.b.ii. below.)

ii. Implementation Schedule for Tier 2

HLDTs

The Tier 2 phase-in schedule for HLDTs is also being finalized as proposed. The phase-in for final Tier 2
standards for HLDTs will start later and
end later than that for LDVs and LLDTs. Fifty percent of each manufacturer’s
HLDTs must meet Tier 2 standards in 2008, and 100 percent must meet Tier
2 standards in 2009. As with the LDV/ LLDTs, the Tier 2 HLDTs must meet a corporate average NO X standard of 0.07 g/mi. This delayed phase-in schedule:

• Provides significant interim emission reductions starting in 2004 (discussed separately below); • Recognizes the relatively high emission standards that currently apply
to HLDTs;

• Provides manufacturers with adequate lead time before they must bring HLDTs into compliance with final Tier 2 standards;

• Provides manufacturers the opportunity to apply and evaluate Tier 2 technology on LDV/LLDTs before having to apply it to HLDTs; and

• Provides manufacturers the opportunity to apply and evaluate Tier 2 technology on HLDTs on a relatively
small scale to meet California LEV II requirements before having to apply it
to HLDTs nationwide.

As with the LDV/LLDTs above, to encourage early introduction of Tier 2 HLDTs and to provide manufacturers with greater flexibility, we are finalizing provisions to permit manufacturers to generate early Tier 2 NO X credits and to use alternative phase-in schedules that still result in 100% phase-in by 2009. (See sections IV.B.4.d.iv. and IV.B.4.b.ii, respectively, below.)

e. Interim Standards

The interim standards discussed below are a major source of emission reductions in the early years of the vehicle control program. The NO X emission standards for LDT2s and LDT4s, which comprise about 40 percent of the fleet, are more stringent than the corresponding standards in the NLEV and CAL LEV I programs. These standards also are important because they set the stage for a smooth transition
to the final Tier 2 standards.

The two groups of vehicles (LDV/ LLDTs and HLDTs) will be approaching the Tier 2 standards from quite different emission ‘‘backgrounds’’. LDV/LLDTs will be at NLEV levels, which require

NO X emissions of either 0.3 or 0.5g/mi

on average, 57 while HLDTs will be at Tier 1 levels facing NO X standards of either 0.98 or 1.53 g/mi, depending on
truck size. These Tier 1 NOX levels for HLDTs are very high (by a factor of 14– 22) relative to our 0.07 g/mi Tier 2 NOX average. To address the disparity in emission ‘‘backgrounds’’, while gaining air quality benefits from vehicles during the phase-in period, we proposed and are finalizing separate interim average

NO X standards for the two vehicle groups during the phase-in period. The provisions described below will apply
in 2004 for all LDVs and LDTs not
certified to Tier 2 standards. The relationship of the interim programs to the final Tier 2 standards is shown in
Table IV.B–3.

Interim vehicles will certify to the
same bins as Tier 2 vehicles. As described earlier in this preamble, we have merged the tables of bins from the NPRM for simplicity and added a few
bins. Bins 9 and 10 were drawn from the tables of interim bins in the NPRM, and are intended only for use during the phase-in years. Therefore, these two
bins will be discontinued after 2006 (2008 for HLDTs).

i. Interim Exhaust Emission Standards for LDV/LLDTs

Beginning with the 2004 model year, all new LDVs, LDT1s and LDT2s not incorporated under the Tier 2 phase-in will be subject to an interim corporate average NO X standard of 0.30 g/mi. This is effectively the LEV NO X emission
standard for LDVs and LDT1s under the NLEV program. 58 This interim program
will hold LDVs and LLDTs to NLEV levels if they are not yet subject to Tier 2 standards during the phase-in. By implementing these interim standards
for LDVs and LLDTs we will ensure that the accomplishments of the NLEV program continue. Additionally, this program will bring about substantial and important NO X emission reductions from LDT2s in the early years of the program. LDT2s will be held to a 0.3 g/

mi NO X average in contrast to a 0.5 g/ mi average in the NLEV program.

Because the Tier 2 standards are phased-in beginning in the 2004 model year, the interim standards for LDVs and LLDTs apply to fewer vehicles each

year, i.e., they are ‘‘phase-out’’
standards. Table IV.B–2 shows the maximum percentage of LDVs and LLDTs subject to the interim standards each year— 75% in 2004, 50% in 2005, 25% in 2006 and 0% in 2007.

As mentioned above, the interim program for LDV/LLDTs is designed to
hold these vehicles to the NLEV NOX level for LDVs and LDT1s, and a few of
our bins are derived from the NLEV program. Our proposal to bring LDT2s
into line with the LDVs and LDT1s during the interim program by requiring all LDVs, LDT1s and LDT2s to meet the same average NO X standard (0.30) g/mi was of concern to industry commenters. In the final rule, we are retaining this requirement, but we are providing an optional NMOG standard of 0.130 for
LDT2s certified to bin 9 when the
manufacturers of those LDT2s elect to bring all of their 2004 model year


### 6738 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

59 In the Tier 1 program, exhaust hydrocarbon standards are in terms of NMHC, not NMOG. However, as we have explained elsewhere in this preamble, NMHC and NMOG results are very similar for gasoline and diesel-fueled vehicles. HLDTs under our interim program and phase 25% of those HLDTs into the 0.20 g/mi average NO X standard. (See ii. below). These provisions are discussed in detail below and also in the Response
to Comments document.

ii. Interim Exhaust Emission Standards for HLDTs

Our interim standards for HLDTs will begin in the 2004 model year similar to our proposal in the NPRM. The Interim Program for HLDTs will require compliance with a corporate average

NO X standard of 0.20 g/mi that will be phased in between 2004 and 2007. The interim HLDT standards, like those for
LDV/LLDTs will make use of the bins in
Tables IV.B. –4 and –5. We believe that our interim standards, which start in 2004, will produce significant emission reductions from HLDTs produced during the interim period. For example,
HLDTs will have to reduce emissions in the interim program relative to the NLEV program. These standards, by themselves, represent a major reduction
in emission standards and we believe it is likely that some manufacturers will apply their Tier 2 technology to HLDTs in order to comply with the interim
standards.

As shown in Table IV.B.–3, the phasein schedule for HLDTs to the 0.20 g/mi corporate average NO X standard will be 25 percent in the 2004 model year (except as noted below), 50 percent in 2005, 75 percent in 2006, and 100 percent in 2007. As for the Tier 2 standards, alternative phase-in schedules (see Section IV.B.4.b.ii.) will be available. The interim program will remain in effect through 2008 to cover those HLDTs not yet phased into the Tier 2 standards (a maximum of 50%). Interim HLDTs not subject to the interim corporate average NO X standard during the applicable phase-in years (2004–2006 or 2005–2006) will be subject to the least stringent bins so
their NO X emissions will be effectively capped at 0.60 g/mi. These vehicles will
be excluded from the calculation to determine compliance with the interim 0.20 g/mi average NO X standard.

This approach will allow more time for manufacturers to bring the more
difficult HLDTs to Tier 2 levels while achieving real reductions from those HLDTs that may present less of a challenge.

Due to statutory leadtime considerations, we were not able to
finalize the HLDT standards to be in effect by the time the 2004 model year begins. For this reason, we are providing incentives for HLDTs to comply with
the Tier 2 standards for all 2004 model year HLDTs. This change and the leadtime issue are discussed further
under section IV.B.4.e. below and also in the Response to Comments
document.

iii. Interim Programs Will Provide
Reductions Over Previous Standards

As is the case with the primary Tier 2 standard structure, the interim programs will focus on NO X but will also provide reductions in NMOG beyond the NLEV program. This is because the interim programs will
reduce emissions from LDT2s and HLDTs compared to their previous
standards. Without the interim standards, HLDTs could be certified to the Tier 1 NMHC levels (0.46 g/mi or 0.56 g/mi). With the interim standards, however, exhaust NMOG 59 should average approximately 0.09 g/mi for all non-Tier 2 LDV/LLDTs and 0.24 g/mi or
less for HLDTs. CO under Tier 1 could be as high as 7.3 g/mi for LDT4s. Under the interim program, CO standards for most bins will be well below 7.3 g/mi.

f. Generating, Banking, and Trading NOX Credits

As proposed in the NPRM and finalized in this notice, manufacturers will be permitted to average the NOX emissions of their Tier 2 vehicles and comply with a corporate average NOX standard. In addition, when a manufacturer’s average NO X emissions fall below the corporate average NOX standard, it can generate NO X credits for later use (banking) or to sell to another manufacturer (trading). NO X credits will be available under the Tier 2 standards,
the interim standards for LDVs and LLDTs, and the interim standards for
HLDTs. These NO X credit provisions will facilitate compliance with the fleet average NO X standards and be very similar to those currently in place for
NMOG emissions under California and federal NLEV regulations.

A manufacturer with an average NOX level for its Tier 2 vehicles in a given model year below the 0.07 gram per mile corporate average standard can generate Tier 2 NO X credits that it can use in a future model year when its average NO X might exceed the 0.07
standard. Manufacturers must calculate their corporate average NO X emissions at year end and then compute credits generated based on how far below 0.07 g/mi the corporate average falls.

Manufacturers will be free to retain any credits they generate for future use or to trade (sell) those credits to other manufacturers. Credits retained or purchased can be used by manufacturers with corporate average

Tier 2 NO X levels above 0.07 g/mi. Under provisions described in Section IV.B.4.d.iv., manufacturers can implement NO X emission reductions as early as the 2001 model year and earn early Tier 2 NO X credits to help LDVs
and LLDTs meet Tier 2 standards. Similarly, manufacturers can earn early credits for HLDTs as early as the 2001 model year. In model years up through 2005, manufacturers can earn extra credits when they certify vehicles to
bins 1 or 2.

Banking and trading of NO X credits
under the interim non-Tier 2 standards
will be similar to that under the Tier 2 standards, except that a manufacturer must determine its credits based upon the 0.30 or 0.20 gram per mile corporate average NO X standard applicable to vehicles in the interim programs. As we proposed in the NPRM, interim credits
from LDVs/LLDTs and interim credits from HLDTs will not be permitted to be used interchangeably due to the differences in the interim corporate average NO X standards. As proposed in the NPRM, there will be no provisions for early banking under the interim
standards and manufacturers will not be
allowed to use interim credits to address
the Tier 2 NO X average standard. This
is because we remain concerned that credits can be generated relatively easily under less stringent standards (the Tier 1 or interim standards) and then used in such a way to delay implementation of
the Tier 2 standards.

Banking and trading of NO X credits
and related issues are discussed in greater detail in Section IV.B.4.d. below.

2. Why Are We Finalizing the Same Set
of Standards for Tier 2 LDVs and LDTs?

Before we provide a more detailed description of the vehicle program, we want to review two overarching principles of today’s rule. The first is our goal to bring all LDVs and LDTs
under the same set of emission standards. Historically, LDTs—and especially the heavier trucks in the LDT3 and LDT4 categories—have been subject to less stringent emission standards than LDVs (passenger cars). In recent years the proportion of light truck sales has grown to approximately 50 percent. Many of these LDTs are minivans, passenger vans, sport utility vehicles and pick-up trucks that are used primarily or solely for personal transportation; i.e., they are used like

passenger cars.

As vehicle preferences have increasingly shifted from passenger cars to light trucks there has been an


### 6739 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

60 Because of the different phase-in percentages and phase-in schedules for the two groups, during the duration of the phase-in (through 2008), manufacturers will average Tier 2 LDV/LLDTs separately from HLDTs. 61 The Alliance proposed NMHC standards in lieu of the NMOG standards we proposed and are finalizing today. We are including a provision in the final rule to accept NMHC results, subject to an adjustment factor, to demonstrate compliance with NMOG standards, although we are not adopting the fixed standards proposed by the Alliance. 62 The interim PM standard in this new bin, which represents a reduction from the NLEV PM standards, should be feasible without aftertreatment. The technologies needed to meet the PM standard we proposed for this bin would likely have required low sulfur diesel fuel, which may not be widely available during the interim program. This change is also discussed in section V.A. accompanying increase in emissions
over what otherwise would have
occurred because of the increase in miles traveled by LDTs and the less stringent standards for LDTs as compared to LDVs. As Section III. above makes clear, reductions in these excess emissions (and in other mobile and stationary source emissions) are seriously needed. Since both LDVs and LDTs are within technological reach of the standards in the Tier 2 bin structure,
and since none of the comments have been persuasive that manufacturers can not meet the standards, we are finalizing our proposal to equalize the regulatory useful life mileage for LDVs and LDTs and apply the same Tier 2 exhaust
emission standard bins to all of them. This program will ensure that
substantial reductions occur in all portions of the light-duty fleet and that
the movement from LDVs to LDTs will
not counteract these reductions.

Once the phase in periods end for all vehicles in 2009, manufacturers will include all LDVs and LDTs together in calculating their corporate average NO X levels. 60 As mentioned above and
described in more detail in Section IV.B.–4. below, manufacturers can choose the emission bin for any test group of vehicles provided that, on a sales weighted average basis, the manufacturer meets the average NO X standard of 0.07 g/mi for its Tier 2 vehicles that year.

Some manufacturers have suggested that a program with different requirements is needed for heavy LDTs. Recognizing that compliance will be most challenging for HLDTs, the delay in the start of the phase-in and the additional phase-in years for those
vehicles will allow manufacturers to delay the initial impact of the Tier 2 standards until the 2008 model year. This represents four additional model years of leadtime beyond the time when passenger cars and LDT1s and LDT2s
will achieve Tier 2 standards in
substantial numbers. We believe this phase-in and other provisions of this rule respond to these concerns. Note that in the NPRM, we requested
comments on the need for different hydrocarbon standards for these vehicles recognizing that a tradeoff often
exists between HC and NO X emissions. We also proposed that several bins have higher hydrocarbon standards for HLDTs during the interim program. We are finalizing these bins as proposed. Also, as an option, we are permitting the use of NMOG values similar to those in the NLEV program for bins 9 and 10 only for certain LDT2s and LDT4s during the interim program (see section IV.B.1.e.ii. above for details).

We are not adopting the Alliance’s proposed phase-in schedule which would have provided a phase-in lasting
until 2011. At the end of the Alliance’s proposed phase-in, all vehicles would comply with an average NO X standard of 0.07 g/mi. A fixed 0.09 NMHC standard would apply to LDVs and
LLDTs while a fixed 0.156 NMHC standard would apply to HLDTs. 61 Our final program provides HLDTs until 2008 before any have to meet 0.07 g/mi on average and permits them to be averaged with LDV/LLDTs beginning in 2009, when all must meet 0.07 g/mi

NO X on average. We believe that eight years is a significant amount of leadtime to apply Tier 2 technology. We heard clearly from the public hearings and written comments that the public sees no justification for and does not want even more time provided for HLDTs. Furthermore, we see no technological need for more time than we proposed. Indeed, many believe that HLDTs should meet the Tier 2 standards in step
with the LDV/LLDTs.

We are not promulgating the fixed NMHC standards suggested by the Alliance, but are sticking with the concept of bins containing lower NMOG
standards connected to lower NO X (and other) standards. We believe that providing final exhaust emission
standards for HLDTs that deviate from
those for LDV/LLDTs would violate one of the overarching principles of the Tier 2 program, i.e. that all LDVs and LDTs should be subject to the same exhaust emission standards. Further, the idea of
NMOG values that differ from
California’s runs counter to other arguments raised by the Alliance that EPA should align bins with California’s to promote 50 state certification of test

groups.
3. Why Are We Finalizing the Same
Standards for Both Gasoline and Diesel
Vehicles?

The second overarching principle of our vehicle program is the use of the
same Tier 2 standards for all LDVs and LDTs, regardless of the fuel they are designed to use. The same exhaust
emission standards and useful life periods we are finalizing today will apply whether the vehicle is built to operate on gasoline or diesel fuel or on
an alternative fuel such as methanol or natural gas. Diesel powered LDVs and
LDTs tend to be used in the same applications as their gasoline counterparts, and thus we believe they
should meet the same standards. Less stringent standards for diesels could
create incentives for manufacturers to build more diesel vehicles, thus endangering the emission reductions expected by this program.

Manufacturers have expressed
concerns that diesel-fueled vehicles would have difficulty meeting NO X and particulate matter levels like those contained in today’s rule. Clearly, these standards will be challenging. As discussed in Section IV.A.–1. above, we expect that the Tier 2 NOX and NMOG standards will be challenging for gasoline vehicles, but that major technological innovations will not be required. For diesels, however, the final

Tier 2 NO X and PM standards will likely require applications of aftertreatment, most likely accompanied by changes in
diesel fuel as such devices are sensitive to diesel fuel quality, particularly sulfur
content. We do not believe such devices will be necessary to meet the top bin for
our interim standards. 62 Given the small percentage of diesel vehicles and the phase-in of the standards, that bin should be sufficient for any
manufacturer to market diesels and still comply with the interim program. We anticipate that manufacturers that
choose to build diesel vehicles for the final Tier 2 standards will adopt aftertreatment technologies such as NO X adsorber catalysts and continuously regenerating particulate traps to meet Tier 2 requirements. We issued an Advanced Notice of Proposed Rulemaking to seek input on potential diesel fuel quality changes on May 13, 1999 (64 FR 26142). We anticipate issuing a Notice of Proposed Rulemaking to reduce the sulfur limit on diesel fuel in the spring of 2000 followed by a final rule in late 2000. Our goal in that rulemaking is to have
low sulfur diesel fuel available which
will allow diesel vehicles to meet the Tier 2 standards, within the bin structure, by the time the Tier 2 standards are required for the entire
fleet.


### 6740 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

63 A ‘‘test group’’ is the basic classification unit for certification of light-duty vehicles and trucks under EPA certification procedures for the CAP2000 program. ‘‘Test group’’ is a broader classification unit than ‘‘engine family’’ used prior to the implementation of the CAP2000 program. We discuss the CAP2000 program in more detail in section V.A.9. of this preamble.

64 The regulatory ‘‘useful life’’ value for Tier 2 vehicles is specifically addressed in Section V.A.2. of this preamble. Full useful life will be 10 years or 120,000 miles for all vehicles except LDT3s and LDT4s, for which it is 11 years or 120,000 miles.
Intermediate useful life, where standards are applicable, is 5 years or 50,000 miles.

65 EPA’s current standards for Clean Fuel Vehicles are less stringent than the Tier 2 standards.

See 40 CFR 88.104–94. The Tier 2 standards will supercede the current CFV standards, and the Agency intends to undertake a rulemaking to revise the CFV standards accordingly.

66 In some cases our bins do not match California’s exactly, because they have higher

NMOG standards. These bins ‘‘cover’’ the California

bin in that a vehicle certified to the California standards will comply with the standards in these

bins. Today, diesels comprise less than one-half of one percent of all LDV/LDT sales. While this is a small fraction, the potential exists for diesels to gain a

considerable market share in the future.

All one need do is review the dramatic increase in recent years of diesel engine use in the lightest category of heavy duty vehicles (8500–10,000 pounds GVWR) to see the potential for significant diesel engine use in LDTs, and perhaps LDVs, in the future. Just ten years ago, diesels made up less than 10 percent of this class of vehicles. In 1998, this fraction approached 50
percent.

The potential impact of large-scale diesel use in the light-duty fleet

underscores the need for the same standards to apply to diesels as other

vehicles. Given the health concerns

associated with diesel PM emissions (see Section III. above), we believe that it is prudent to address PM emissions

from diesel LDVs and LDTs while their numbers are relatively small. In this way the program can minimize the PM impact that would accompany significant growth in this market segment while allowing manufacturers to incorporate low-emission technology into new light-duty diesel engine designs. 4. Key Elements of the Vehicle Program
The previous subsections IV.B.–1.2. and 3. provide an overview of the Tier 2 vehicle program and the two key principles it is built on. This subsection elaborates on the major vehicle-related elements of today’s rule. Later in this preamble, Section V.A. discusses the rest of the vehicle provisions.

a. Basic Exhaust Emission Standards
and ‘‘Bin’’ Structure

Our final Tier 2 program contains a basic requirement that each manufacturer meet, on average, a full
useful life NO X standard of 0.07 g/mi for
all its Tier 2 LDVs and LDTs. Manufacturers will have the flexibility
to choose the set of standards that a particular test group 63 of vehicles must meet. For a given test group of LDVs or LDTs, manufacturers will select a set of
full useful life 64 standards from the same row (‘‘emission bin’’ or simply ‘‘bin’’) in Table IV.B.–4. below. Each bin contains a set of individual NMOG, CO, HCHO, NO X , and PM standards. For technology harmonization purposes, our proposed emission bins include or otherwise cover all of those adopted in California’s LEV II program. 65,66

In the NPRM, we proposed that
interim vehicles and Tier 2 vehicles (except for those Tier 2 vehicles in the lowest bins) would also have to meet intermediate useful life standards, i.e., standards that apply for 5 years or 50,000 miles. We are finalizing these

intermediate useful life standards as proposed. Where we have added new full life bins, we have included corresponding intermediate life bins as appropriate. Our intermediate life standards are generally aligned with California’s, they only impact the higher bins, and we do not believe they add substantial burden to the program. Further, they provide a check on the allowed emission deterioration during the life of the vehicle. For the final rule, we have made two changes involving intermediate life standards. First, we are providing that diesel vehicles, which will likely certify to bin 10 during the interim program, may opt not to meet
the intermediate life standards
associated with this bin. Low sulfur diesel fuel may be needed for diesels to
meet our interim intermediate life standards and it is not likely to be widely available during the time frame of the interim program. Secondly, for all vehicles, we are finalizing a provision
that will make intermediate life standards optional for any test group
that is certified to a full useful life of 150,000 miles. This provision is
described in more detail with other
useful life issues in section V.B.



### TABLE 

### IV.B–4.—T IER 

### 2 L IGHT

### –D UTY 

### F ULL 

### U SEFUL 

### L IFE 

### E XHAUST 

### E MISSION 

### STANDARDS

[Grams per mile]

Bin No. NOX NMOG CO HCHO PM Comments

10 ............................................... 0.6 0.156/0.230 4.2/6.4 ......... 0.018/0.027 0.08 ( a,b,c,d) 9 ................................................. 0.3 0.090/0.180 4.2 ............... 0.018 ........... 0.06 ( a,b,e)

The above temporary bins expire in 2006 (for LDVs and LLDTs) and 2008 (for HLDTs)

8 ................................................. 0.20 0.125/0.156 4.2 ............... 0.018 ........... 0.02 (b,f )

7 ................................................. 0.15 0.090 ........... 4.2 ............... 0.018 ........... 0.02

6 ................................................. 0.10 0.090 ........... 4.2 ............... 0.018 ........... 0.01

5 ................................................. 0.07 0.090 ........... 4.2 ............... 0.018 ........... 0.01

4 ................................................. 0.04 0.070 ........... 2.1 ............... 0.011 ........... 0.01

3 ................................................. 0.03 0.055 ........... 2.1 ............... 0.011 ........... 0.01

2 ................................................. 0.02 0.010 ........... 2.1 ............... 0.004 ........... 0.01

1 ................................................. 0.00 0.000 ........... 0.0 ............... 0.000 ........... 0.00

Notes:

a Bin deleted at end of 2006 model year (2008 for HLDTs).

b The higher temporary NMOG, CO and HCHO values apply only to HLDTs and expire after 2008.

c An additional temporary higher bin restricted to MDPVs is discussed in section IV.B.4.g.

d Optional temporary NMOG standard of 0.280 g/mi applies for qualifying LDT4s and MDPVs only.

e Optional temporary NMOG standard of 0.130 g/mi applies for qualifying LDT2s only, see text.

f Higher temporary NMOG standard is deleted at end of 2008 model year.


### 6741 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

TABLE 

### IV.B.–5.—L IGHT

### -D UTY 

### I NTERMEDIATE 

### U SEFUL 

### L IFE 

### (50,000 M ILE 

### ) E XHAUST 

### E MISSION 

### STANDARDS

[Grams per mile]

Bin No. NOX NMOG CO HCHO PM Comments

10 ............................................... 0.4 0.125/0.160 3.4/4.4 ......... 0.015/0.018 ( a,b,c,d,f,h) 9 ................................................. 0.2 0.075/0.140 3.4 ............... 0.015 ........... ( a,b,e,h)

The above temporary bins expire in 2006 (for LDVs and LLDTs) and 2008 (for HLDTs)

8 ................................................. 0.14 0.100/0.125 3.4 ............... 0.015 ........... ( b,g,h) 7 ................................................. 0.11 0.075 ........... 3.4 ............... 0.015 ........... ( h) 6 ................................................. 0.08 0.075 ........... 3.4 ............... 0.015 ........... ( h) 5 ................................................. 0.05 0.075 ........... 3.4 ............... 0.015 ........... ( h)

Notes:

a Bin deleted at end of 2006 model year (2008 for HLDTs).

b The higher temporary NMOG, CO and HCHO values apply only to HLDTs and expire in 2008.

c An additional higher temporary bin restricted to MDPVs is discussed in section IV.B.4.g.

d Optional temporary NMOG standard of 0.195 g/mi applies for qualifying LDT4s and MDPVs only.

e Optional temporary NMOG standard of 0.100 g/mi applies for qualifying LDT2s only, see text.

f Intermediate life standards are optional for diesels certified to bin 10.

g Higher temporary NMOG value deleted at end of 2008 model year.

h. Intermediate life standards are optional for any test group certified to a 150,000 mile useful life (if credits are not claimed ).

Under a ‘‘bins’’ approach, a manufacturer may select a set of emission standards (a bin) to comply with, and a test group must meet all standards within that bin. Ultimately,
the manufacturer must also ensure that the emissions of a targeted pollutant—

NO X in this case—from all of its vehicles taken together meet a ‘‘corporate average’’ emission standard. This corporate average emission
standard ensures that a manufacturer’s production yields the required overall emission reductions. (See Section IV.B.–
4.c. below for more discussion of the corporate average NO X standard.)

In addition to the Tier 2 standards described above, we are also finalizing an interim average NO X standard
derived from the LDV/LDT1 NLEV program to cover all non-Tier 2 LDVs and LLDTs during the Tier 2 phase-in. We are finalizing a separate interim average NO X standard for HLDTs. As in the Tier 2 program, manufacturers will
select bins from Table IV.B.–4 to use to comply with the interim standards. Bins
with NO X values at or above 0.07 g/mi
also have associated intermediate life
standards which are shown in Table IV.B.–5. (We describe the interim
standards in detail in Section IV.B.4.e. below.)

i. Why Are We Including Extra Bins?

Compared to the CalLEV II program, our Tier 2 proposal included additional bins. The California program contains
no bins that will allow NOX levels above the 0.07 g/mi level. Therefore, under the California program, no engine family can be certified above 0.07 g/mi, even with the application of offsetting credits. We proposed to add two bins (with NO X values of 0.15 and 0.20)
above the 0.07 bin and another below (with a NO X value of 0.04) to provide
manufacturers with additional flexibility. Based upon comments
received from the Alliance and others that additional bins provide important added flexibility, we are finalizing a
total of three bins above the LEV level (the additional bin has a NOX value of 0.10 g/mi) and are adding one more below the LEV level (this additional bin
has a NO X value of 0.03 g/mi). Due to
the NO X averaging requirement of this rule, these bins will not result in any

increase in NO X emissions. Further,
these bins will address concerns raised by some that a wider variety of bins, and bins with higher NO X values, are
needed to avoid a situation where the Tier 2 program discourages the development of advanced technology high fuel economy vehicles, which may, at least in their earliest years, have NOX emissions higher than more
conventional vehicles.

In our NPRM we proposed that during the Tier 2 phase-in years (through 2006 for LDV/LLDTs and 2008 for HLDTs), bins from the applicable interim program would be available to enhance the flexibility of the program by providing manufacturers with additional bins having NO X standards above 0.07 g/mi. In the NPRM, we showed the interim bins in separate
tables for LDV/LLDTs and HLDTs. There was considerable overlap across
the two tables and with the Tier 2 bins. In this final rule, we have consolidated
the interim bins and the Tier 2 bins into one table for simplicity and ease of reference. The interim programs for
non-Tier 2 vehicles are described in
detail in section IV.B.4.e.

While some commenters were
concerned about the existence of bins
above NO X = 0.07 g/mi, we believe that the additional higher bins actually provide incentive for manufacturers to produce vehicles below 0.07 g/mi of

NO X . We believe this incentive exists
because manufacturers will have some vehicles (especially larger LDTs) that they might find more cost effective to certify to levels above the 0.07 g/mi average standard. However, to do this they will have to offset those vehicles in

our NO X averaging system with vehicles certified below 0.07 g/mi. The bins at

NO X = 0.04 g/mi and NO X = 0.03 g/mi will provide greater opportunity to do this. Thus, the extra bins serve two purposes; they provide additional flexibility to manufacturers to address technological differences and costs, and they provide those manufacturers with incentives to produce cleaner vehicles
and thus advance emission control technology.

We are finalizing a bins approach
with the bins shown in Tables IV.B.4 and 5 to provide adequate and appropriate emission reductions and manufacturer flexibility. This structure will help to accelerate technological innovation. We requested comment on whether we should include up to two
additional bins between NO X = 0.07 and

NO X = 0.15. Based upon manufacturer comment, we have added an additional bin (bin 6 ) with NO X = 0.10. This bin will provide greater flexibility for manufacturers who may find it more cost-effective to produce some vehicles slightly above 0.07 but have difficulties meeting a 0.07 g/mi average NOX standard if they must certify them to a

NO X level of 0.15 g/mi.

We requested comment on whether
our Tier 2 bin in the NPRM with NOX = 0.20 (our final bin 8) should be eliminated when the Tier 2 phase-in is completed (after 2007 for LDV/LLDTs


### 6742 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

67 For Tier 2 vehicles (and for interim vehicles), the term ‘‘U.S. sales’’ means, for a given model year, those sales in states other than California and any states that have adopted the California program. and after 2009 for HLDTs). Numerous commenters argued that our highest
bins were too lenient. Comments from manufacturers were opposed to eliminating bin 8 and we see little downside to having bins higher than the

0.07 NO X standard, given that, for all of the vehicles that will use this bin,
manufacturers will have to offset the excess emissions by selling vehicles certified below 0.07 g/mi NO X under the averaging requirement. Thus, we are retaining bin 8.

b. The Program Will Phase in the Tier
2 Vehicle Standards Over Several Years

i. Primary Phase-In Schedule

We are finalizing as proposed our plan to phase in the Tier 2 standards for LDV/LLDTs over a four year period beginning in 2004 and we are also finalizing as proposed a delayed two year phase-in beginning in 2008 for HLDTs. These phase-in schedules are
shown in Table IV.B.–2 and are also shown separately in Tables IV.B.–6 and 7. We believe the flexibility of this dual phase-in approach is appropriate because the Tier 2 program will encompass all light-duty vehicles and trucks and will result in widespread applications of upgraded and improved technology across the fleet. The program will require research, development,proveout, and certification of all lightduty models, and manufacturers may need longer lead time for some vehicles, especially HLDTs. Also, manufacturers may wish to time compliance with the
Tier 2 standards to coincide with other changes such as the roll out of new engines or new models. In order to begin the introduction of very clean vehicles as soon as possible while avoiding imposing unnecessary inefficiencies on vehicle manufacturers, we believe this practical but aggressive phase-in schedule effectively balances air quality, technology, and cost
considerations.

In each year, manufacturers will have to ensure that the specified fraction of
their U.S. sales: 67

• Meets Tier 2 standards for exhaust emissions, including Supplemental Federal Test Procedure (SFTP) standards (discussed in Section V.A.–3. below);

• Meets Tier 2 standards for evaporative emissions (discussed in Section IV.B.–4.f. below); and

• Meets the corporate average Tier 2

NO X standard. Manufacturers will have to meet the Tier 2 exhaust requirements (i.e., all the standards of a particular bin plus the SFTP standards) using the same vehicles. Vehicles not covered by the Tier 2 standards during the phase-in years (2004–2008) will have to meet
interim standards described in Section IV.B.4.e. below and the existing evaporative emission as well as the applicable SFTP standards.

Manufacturers can elect to meet the percentage phase-in requirements for evaporative and exhaust emissions using two different sets of vehicles. We
believe that because of interactions between evaporative and exhaust control strategies, manufacturers will generally address the Tier 2 evaporative phase-in with the same vehicles that they use to meet the exhaust phase-in. However, the primary focus of today’s proposal is on exhaust emissions, and the flexibility for manufacturers to use different sets of vehicles in complying with the phase-in schedule for evaporative standards and for the
exhaust standards will have no
environmental down side that we are aware of. It is possible that some exhaust emission improvements might even occur sooner than they otherwise
would if a manufacturer is able to move
ahead with the roll-out of a model with
cleaner exhaust emissions without having to wait for the development of suitable evaporative controls to be completed for that model.



### TABLE 

### IV.B.–6.—P RIMARY 

### P HASE 

### -I N 

### S CHEDULE FOR 

### SALES OF 

### T IER 

### 2

LDVS AND 

### LLDTS

Model year Required percentage oflight-duty vehicles and light

light-duty

trucks (percent)

2004 ...................................... 25

2005 ...................................... 50

2006 ...................................... 75

2007 ...................................... 100



### TABLE 

### IV.B.–7.—P RIMARY 

### P HASE 

### -I N 

### S CHEDULE FOR 

### SALES OF 

### T IER 

### 2

HLDTS

Model year Required percentage ofheavy lightduty trucks (percent)

2008 ...................................... 50

2009 ...................................... 100

We are finalizing our proposed phasein approach, in which vehicle sales will be determined according to the ‘‘point
of first sale’’ method outlined in the NLEV rule. Vehicles with points of first
sale in California or a state that has adopted the California LEV II program (if any) will be excluded from the calculation. The ‘‘point of first sale’’ method recognizes that most vehicle
sales will be to dealers and that the dealers’ sales will generally be to customers in the same geographic area.
While some sales to California residents (or residents of states that adopt California standards) may occur from other states and vice-versa, we believe
these sales will be far too small to have any significant impact on the air quality benefits of the Tier 2 program or the manufacturers’ ability to demonstrate compliance.

ii. Alternative Phase-In Schedule

We are finalizing, as proposed, that manufacturers may introduce vehicles earlier than required to earn the flexibility to make offsetting adjustments, on a one-for one basis, to the phase-in percentages in later years. However, they will still need to reach 100% of sales in the 2007 model year (2009 for HLDTs). Manufacturers will have the option to use this alternative to meet phase-in requirements for LDV/ LLDTs and/or HLDTs. They can use separate alternative phase-in schedules for exhaust and evaporative emissions, or an alternative phase-in schedule for one set of standards and the primary (25/50/75/100% or 50%/100%)
schedule for the other.

Under these alternative schedules,
manufacturers will have to introduce vehicles that meet or surpass the 0.07 g/

mi Tier 2 NO X average standard before they are required to do so, or else introduce vehicles that meet or surpass the 0.07 standard in greater quantities than required. Alternative phase-in schedules essentially credit the manufacturer for its early or accelerated
efforts and allow the manufacturer greater flexibility in subsequent years during the phase-in. Thus, the alternative phase-in schedule provisions provide incentive and flexibility to
manufacturers to introduce Tier 2 vehicles before 2004 (or 2008 for HLDTs).

As outlined in the NPRM, an alternative phase-in schedule will be acceptable if it passes a specific mathematical test. We have designed the test to provide manufacturers benefit from certifying to the Tier 2 standards early while ensuring that significant
numbers of Tier 2 vehicles are introduced during each year of the alternative phase-in schedule. To test an alternative schedule, a manufacturer


### 6743 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

68 For interim vehicles, this average NO X standard

will be 0.20 for HLDTs and 0.30 for LDV/LLDTs. Compliance with these interim average standards will be calculated in the same manner as compliance with the 0.07 standard. must sum its yearly percentages of Tier 2 vehicles beginning with model year 2001 and compare the result to the sum that results from the primary phase-in
schedule. If an alternative schedule scores as high or higher than the base option, then the alternative schedule is acceptable. The mathematical technique to evaluate alternative phase-in schemes
is somewhat similar to that used in our
NLEV rule and in California rules.

For LDV/LLDTs, the final sum of percentages must equal or exceed 250—
the sum that results from a 25/50/75/ 100 percent phase-in. For example, a 10/25/50/65/100 percent phase-in that begins in 2003 will have a sum of 250 percent and is acceptable. In this example, assuming constant levels of production, each Tier 2 vehicle sold early (i.e. in 2003) will permit the
manufacturer to sell one less Tier 2 vehicle in the last phase-in year (2006). A 10/20/40/70/100 percent phase-in that begins the same year has a sum of 240 percent and is not acceptable. For HLDTs, the sum must equal or exceed 150 percent.

To ensure that significant numbers of
Tier 2 vehicles are introduced in the 2004 time frame, manufacturers will not be permitted to use alternative phase-in schedules that delay the implementation of the Tier 2 LDV/LLDT requirements, even if the sum of the phase-in percentages meets or exceeds
250. Such a situation could occur if a manufacturer delayed implementation of its Tier 2 production until 2005 and began a 75/85/100 percent phase-in that year. To protect against this possibility, we are finalizing the proposed requirement that for any alternative phase-in schedule, a manufacturer’s phase-in percentages from the 2004 and earlier model years sum to at least 25%. In the final rule we are including an additional measure of flexibility to the requirements for alternative phase-in schedules. We will permitmanufacturers to achieve a 2004 phasein of less than 25%, but no less than 20%, provided that in 2005 they make up the shortfall in a two-for-one manner. So, as an example, a manufacturer that phased in 5% in 2003 and 15% in 2004 would achieve a total of 20% through the 2004 model year and would need to comply with Tier 2 requirements for at least 60% of its
LDV/LLDTs in 2005. We believe that this flexibility is appropriate because the required response for 2005 model year vehicles more than makes up for
the environmental loss from the 2004 model year vehicles.

We requested comment on whether alternative phase-in schedules should be structured to permit manufacturers to extend phase in past the final year of the primary phase-in schedule (2007 or 2009). While the Alliance proposal and comments clearly support phase-ins that run past 2007 and 2009, other commenters were opposed to any extensions of the phase-in period. In
fact most commenters who addressed the length of the phase-in indicated, as previously discussed, that the phase-in
for HLDTs should be moved ahead to
2007 to coincide with LDV/LLDTs. We are not finalizing any provisions that will permit alternative phase-in schedules to provide additional time for manufacturers to meet any final 100% compliance year.

In the NPRM, we pointed out that phase-in schedules, in general, add little flexibility for manufacturers with limited product offerings because a manufacturer with only one or two test groups can not take full advantage of a25/50/75/100 percent or similar phasein. For manufacturers meeting EPA’s
definition of ‘‘small volume manufacturer,’’ we proposed to exempt those manufacturers from the phase-in schedules and require them to simply comply with the final 100% compliance requirement. We are finalizing this provision for small volume manufacturers. This provision is only intended to apply to small volume
manufacturers and not to small test groups of larger manufacturers.

For larger manufacturers having a limited product line, we recognize that our phase-in schedule may lack flexibility, however, we are not including any provisions to address this
issue as we are for small volume
manufacturers because we do not
believe these manufacturers need the
relief and we do not want to sacrifice any air quality benefits of the program.

c. Manufacturers Will Meet a ‘‘Corporate Average’’ NO X Standard

While the manufacturer will be free to certify a test group to any applicable bin of standards in Table IV.B.–2, it will have to ensure that the sales-weighted average of NO X standards from all of its test groups of Tier 2 vehicles meet a full useful life standard of 0.07 g/mi. 68 Using a calculation similar to that for the NMOG corporate average standard in the California and NLEV programs,
manufacturers must determine their compliance with the corporate average

NO X standard at the end of the model year by computing a sales weighted average of the full useful life NOX standards from each bin. Manufacturers must use the following formula:



### Corporate total Tier Average NO Tier 2 NO std for each bin) (sales for each bin)

sales X X



### = ×



# ∑ (

2

Manufacturers must exclude vehicles sold in California or states adopting
California LEV II standards from the calculation. As indicated above, manufacturers must compute separate

NO X averages for LDV/LLDTs and HLDTs through model year 2008.

The corporate average NO X standards of the primary Tier 2 program and the interim programs for LDV/LLDTs andHLDTs will ensure that expected fleetwide emission reductions are achieved. At the same time, the corporate average standards allow us to permit the sale of some vehicles above the levels of the average standards to address the greater technological challenges some vehicles
face and to reduce the overall costs of the program. We discuss how manufacturers can generate, use, buy
and sell NO X credits under the interim and Tier 2 programs in the next
subsection.

Given the corporate average NO X standards, we do not believe a corporate average NMOG standard as used by California is essential because meeting the corporate average NO X standard will automatically bring the NMOG fleet average to approximately 0.09 g/mi or
below.

d. Manufacturers Can Generate, Bank,
and Trade NO X Credits

i. General Provisions

As mentioned in the Overview above, we are finalizing our proposal that manufacturers with year-end corporate average NO X emissions for their Tier 2 vehicles below 0.07 g/mi can generate

Tier 2 NO X credits. Credits can be saved (banked) for use in a future model year


### 6744 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

or for trading (sale) to another
manufacturer. Manufacturers can use credits if their corporate average NOX emissions are above 0.07 g/mi.

As proposed, the Tier 2 standards will apply regardless of the fuel the vehicle is designed for, and there will be no restrictions on averaging, banking or trading of credits across vehicles of different fuel types. Consequently, a gasoline fueled LDV might help a manufacturer generate NOx credits in one year that could be banked for the next year when they could be used to average against NO X emissions of a
diesel fueled LDT within the appropriate averaging structure.

Because of the split phase-in and the different interim programs we are finalizing for the two different groups of vehicles (LDV/LLDTs and HLDTs), we are also finalizing the proposed requirement that manufacturers compute their corporate Tier 2 NOX averages separately for LDV/LLDTs and HLDTs through 2008. As we proposed, credit exchanges between LDVs/LLDTs
and HLDTs will not be allowed nor will credit exchanges across the interim programs or between the interim programs and the final Tier 2 program
be allowed. These restrictions will end with the 2009 model year at which time both phase-ins and all interim standards will have ended and the program will permit free averaging across all Tier 2 vehicles. As noted in the NPRM, we are concerned that allowing cross-trading
between interim and Tier 2 vehicles will reduce the expected benefits of the program and delay fleet turnover to Tier
2 emission levels. For this reason we did not propose and are not finalizing to permit such exchanges.

ii. Averaging, Banking, and Trading of

NO X Credits Fulfills Several Goals
We explained in the NPRM why we believe the provisions for averaging, banking, and trading of NO X credits (ABT) will be valuable. In short:

• An ABT program is an important
factor that EPA takes into consideration in setting emission standards that are appropriate under section 202 of the
Clean Air Act. ABT allows us to consider a more stringent emission standard than might otherwise be appropriate under the CAA, since ABT reduces the cost and improves the technological feasibility of achieving the standard;

• ABT enhances the technological feasibility and cost effectiveness of the proposed standard and allows the
standard to be attainable earlier than might otherwise be possible;

• ABT provides manufacturers with additional product planning flexibility and the opportunity for a more cost effective introduction of product lines;

• ABT creates incentive for early introduction of new technology, allowing certain engine families to act as trail blazers for new technology;

We view the ABT provisions in today’s rule as environmentally neutral because the use of credits by some vehicles is offset by credits generated by other vehicles. However, when coupled with the new standards, ABT will have
environmental benefits because it
allows the new standards to be implemented earlier than would otherwise be appropriate.

iii. How Manufacturers Can Generate
and Use NO X Credits

Manufacturers will determine their year-end corporate average NO Xemission level by computing a salesweighted average of the NO X standard
from each bin to which the manufacturer certifies any LDVs or

LDTs. Tier 2 NO X credits will be generated when a manufacturer’s average is below the 0.07 gram per mile corporate average NO X standard, according to this formula:

NO X Credits=(0.07 g/mi

¥ Corporate

Average NO X)×Sales

The manufacturer can use these NOX credits in future years if its corporate

NO X average is above 0.07, or it can trade (sell) the credits to other
manufacturers. Tier 2 credits can be generated via this mechanism beginning in the first phase-in year, i.e., 2004 for
LDV/LLDTs and 2008 for HLDTs. The
use of NO X credits will not be permitted
to address Selective Enforcement Auditing or in-use testing failures.

The enforcement of the NO X averaging standard will occur through the vehicle’s certificate of conformity. A manufacturer’s certificate of conformity will be conditioned upon compliance with the averaging provisions. The
certificate will be void ab initio if a manufacturer fails to meet the corporate average NO X standard and does not obtain appropriate credits to cover its shortfall in that model year or in the next three model years (see deficit carryforward provision below).
Manufacturers will need to track their certification levels and sales unless they produce only vehicles certified to bins containing NO X levels of 0.07 g/mi or below and do not plan to bank NOX credits.

iv. Manufacturers Can Earn and Bank Credits for Early NO X Reductions

In the NPRM, we proposed that to the extent a manufacturer’s corporate average NO X level of its ‘‘early Tier 2’’ vehicles was below 0.07 g/mi, the
manufacturer could bank NO X credits for later use. We recognize (and the comments assert) that this provision may be lightly used, because it requires a large reduction from prior standards to produce any credits. However, our goal is to bring vehicles to Tier 2 levels as quickly as possible and we are concerned that any other approach could provide credits for reductions manufacturers would make relatively easily from previous, higher standards.
Such credits would then be used to delay the impact of the 0.07 g/mi NOX standard. Further, we believe that our provision for alternative phase-in schedules provides what is essentially a supplemental, or perhaps even primary, early banking program, in that it permitsmanufacturers to trade-off earlier phasein percentages for later phase-in percentages. To provide manufacturers with greater flexibility and with incentives to certify, produce and sell Tier 2 vehicles as early as possible, we are finalizing the alternative phase-in provisions. (See IV.B.4.b.ii above.) Under such schedules, a manufacturer can certify vehicles to an average NOX level of 0.07 g/mi or below in years prior to the first required phase-in year and then phase its remaining vehicles in over a more gradual phase-in schedule that will still lead to 100% compliance by 2007 (2009 for HLDTs).

Thus, we are finalizing our provision for early NO X credits essentially as proposed. To the extent that a manufacturer’s corporate average NO X level of its ‘‘early Tier 2’’ vehicles is below 0.07 g/mi, the manufacturer can
bank NO X credits for later use. Manufacturers will compute these early credits by calculating a sales-weighted corporate average NO X emission level of their Tier 2 vehicles, as in the basic Tier 2 program described above. In section IV.B.4.d.vii. below, we describe provisions we are adding to the final
rule that will enable manufacturers to generate extra credits from vehicles certified to very low levels. In addition to encouraging production of very clean vehicles, these provisions, which apply beginning in 2001, will enhance the abilities of manufacturers to generate early credits.

Early Tier 2 credits will have all the same properties as credits generated by vehicles subject to the primary phase-in schedule. We proposed that these credits could not be used in the NLEV, Tier 1 or interim program for non-Tier 2 vehicles in any way. We are finalizing this restriction as proposed. We are also finalizing as proposed that the NMOG emissions of these vehicles (LDVs and LLDTs only) can be used in the


### 6745 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

69 Because of the limited duration of the interim programs, we proposed that a manufacturer could carry a credit deficit in the interim program forward until the 2006 model year (2008 for HLDTs). The interim program, in its entirety, lasts only five years and therefore we saw little risk of prolonged

deficits. calculation of the manufacturer’s corporate average NMOG emissions under NLEV through 2003.

To provide manufacturers with maximum flexibility in the period prior to 2004, when LDV/LLDT useful lives will still be at 100,000 miles, we proposed and are finalizing that manufacturers may choose between the Tier 2 120,000 mile useful life or the current 100,000 mile useful life requirement for early Tier 2 LDV/ LLDTs. (HLDTs already have a 120,000 mile useful life.) Early LDV/LLDT NOX credits for 100,000 mile useful life vehicles will have to be prorated by 100,000/120,000 (5/6) so that they can be properly applied to 120,000 mile Tier
2 vehicles in 2004 or later.

We proposed to restrict early banking
of HLDT Tier 2 NO X credits to the four year period from 2004–2007. This
restriction was due to a concern about excessive credits generation if a longer credit generation period was available.
Based on our review of the comments
and from reconsideration of the restrictive nature of our approach for early credits, we are much less concerned that allowing generation of early HLDT Tier 2 credits in years prior
to 2004 will result in excessive credits. Prior to 2004, manufacturers will only be required to meet the Tier 1 standards which are much higher than the final
Tier 2 standards. Manufacturers will have to make large cuts in emissions to
bank the small amount of credits offered by our early banking provision. Further, we recognize that vehicles that meet the Tier 2 standards early provide an environmental benefit, and the earlier that benefit occurs, the earlier that areas
can use such benefits to reach or come close to attainment. Lastly, we believe it is appropriate to match the period of early credit generation with the years inwhich we will permit alternative phasein schedules. Consequently, we are finalizing our provisions for early banking such that manufacturers may bank early Tier 2 NO X credits in model years 2001–2007.

We recognize that vehicles generating early Tier 2 NO X credits may be doing
so without the emissions benefit of low sulfur fuel, and thus these vehicles may
not achieve the full in-use emission reduction for which they received
credit. When these credits are used to permit the sale of higher-emitting vehicles, there may be a net increase in emissions. For the most part, this is a problem anyway, since NLEV vehicles are also sensitive to gasoline sulfur. We believe that the benefits of early introduction of Tier 2 technology described above are significant enough that they are worth the risk of some emission losses that might occur if and when the early credits are used. Also,
we believe that some fuel sulfur reductions will occur prior to 2004 as refiners upgrade their refineries or bring new refining capacity on stream in anticipation of the 2004 requirements and take advantage of the phase-in proposed in the gasoline sulfur ABT program (described in Section IV.C. below).

v. Tier 2 NO X Credits Will Have Unlimited Life

We discussed in the preamble to the NPRM why we did not propose to apply the California schedule of discounting unused credits adopted for NMOG credits in the NLEV program. This
schedule serves to limit credit life throughout the program by reducing unused credits to 50, 25 and 0 percent of their original number at the end of the second, third and fourth year, respectively, following the year in which they were generated. We agree that such a scheme may be appropriate in the California program with its declining NMOG average standard, butin the federal program, once the phasein period ends in model year 2009, all LDVs and LDTs will comply on average
with a fixed Tier 2 NOX standard.

Credits allow manufacturers flexibility to meet standards cost effectively and to address unexpected
shifts in sales mix. When matched with

a NO X average standard, credits provide flexibility constrained by the requirement that all vehicles, on average, must comply with a fixed
standard. Defined bins of standards prevent any one vehicle from having extremely high emissions, while the need to offset higher vehicles with lower vehicles to meet an average NOX standard prevents large numbers of vehicles from utilizing the higher bins.

We requested comment in the NPRM on the need for discounting of credits or
limits on credit life and what those discount rates or limits, if any, should
be. The 0.07 NO X emission standard in the Tier 2 program is quite stringent and does not present easy opportunities to generate credits. The degree to which
manufacturers invest the resources to
achieve extra NO X reductions provides environmental benefit for years to come and it is appropriate that the manufacturer get credits. We do not
want to take measures to reduce the
incentive for manufacturers to bank
credits nor do we want to take measures to encourage unnecessary credit use. Consequently we are finalizing our proposal that Tier 2 NO X credits, including early credits, have unlimited
lives. vi. NO X Credit Deficits Can Be Carried
Forward

When a manufacturer has a NOX deficit at the end of a model year—that is, its corporate average NO X level is above the required corporate average

NO X standard—we proposed that the manufacturer could carry that deficit forward into the next model year. Such a carry-forward could only occur after the manufacturer used any banked
credits. If the deficit still existed and the
manufacturer chose not to or was unable to purchase credits, the deficit could be
carried over. At the end of that next model year, according to our proposal,
the deficit would need to be covered with an appropriate number of NOX credits that the manufacturer generated or purchased. Any remaining deficit would be subject to an enforcement action. To prevent deficits from being carried forward indefinitely, the manufacturer would not be permitted to run a deficit for two years in a row. 69

Manufacturers made the persuasive case that by the time they can tabulate their average NO X emissions for a particular model year, the next model year is likely well underway and it is too late to make calibration, marketing or sales mix changes to adjust that year’s credit generation. Therefore, based upon comments, we are finalizing a modified approach to credit deficits such that a manufacturer having a credit deficit in the interim or Tier 2 program can carry
that deficit forward for a total of three years, but the manufacturer must apply
all its available credits to that deficit on
a one-for-one basis in each of the first two succeeding model years. If the deficit is not covered by the third model year, the manufacturer must apply credits at a rate of 1.2:1. No deficit may be carried into the fourth year. In order
to accommodate this modification to our proposal, we must also modify our proposed provision that would have prevented manufacturers from running a deficit in two consecutive model years
so that deficits can not be shifted from one year to the next and thus carried forward indefinitely. Because we are permitting, in this final rule, deficits to be carried forward for as long as three years we are finalizing that
manufacturers can not run a deficit in any year in which it is paying off a deficit from a previous year. The effect of this provision is the same as that in


### 6746 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

the NPRM— to keep manufacturers from shifting deficits forward indefinitely.

We note that under our modified final approach, manufacturers will have the flexibility to carry deficits from the interim program forward into the final Tier 2 program. This feature is likely to be used only in an extreme situation
since the Tier 2 credits needed to offset
the interim credit deficit will be more difficult to generate. Consequently, we do not believe this provision is inconsistent with our approach of segregating interim and Tier 2 credits. In fact, manufacturers electing to cover an
interim credit deficit with Tier 2 credits will likely have to accelerate the introduction of Tier 2 vehicles to get the necessary credits to cover the deficit.

We are finalizing that small volume manufacturers may not use the credit deficit carryforward provision until they have been in compliance with the relevant average NO X standard for one model year. In section V of this preamble we explain that we are not requiring small volume manufacturers to comply with intermediate phase-in requirements under our interim or Tier 2 phase-ins. Rather, they will just have to comply for all of their vehicles in the last phase-in year. Because they do not have to comply with intermediate phase-in requirements, small volume manufacturers effectively get more time to comply (as much as three years). We
do not want to create a situation where they could get even more time to comply by using the credit deficit carryforward provision.

vii. Encouraging the Introduction of
Ultra-Clean Vehicles

We requested comment in the NPRM as to whether we should provide
additional NO X credits for vehicles that certify to very low levels. We stated in
the NPRM that we believe it is appropriate to provide inducements to manufacturers to certify vehicles to very
low levels and that these inducements may help pave the way for greater and/
or more cost effective emission
reductions from future vehicles. We believe it is important in a rule of this nature to provide extra incentive to encourage manufacturers to produce and market very clean vehicles. We believe this is especially important in the earliest years of the program when
manufacturers must make resource commitments to technologies andvehicle designs that will have multiyear life spans. We believe this program provides a strong incentive for
manufacturers to maximize their development and introduction of the best available vehicle/engine emission control technology, and this in turn provides a stepping stone to the broader introduction of this technology soon thereafter. Early production of cleaner vehicles enhances the early benefits of our program and vehicles certified to these lowest bins produce not just lower

NO X but also lower NMOG, CO and
HCHO emissions. If a manufacturer can be induced to certify to a lower bin by the promise of reasonable extra credits,
the benefits of that decision to the program may last for many years.

We are finalizing provisions to permit manufacturers, at the beginning of the program, to weight LDV/Ts certified to the lowest two bins more heavily when calculating their fleet average NO X emissions. Under this provision, which applies through the 2005 model year, manufacturers may apply a multiplier to
the number of LDV/Ts sold that are certified to bins 1 and 2 (ZEVs and SULEVs in California terms). This adjusted number will be used in the calculation of fleet average NO X emissions for a given model year and will allow manufacturers having
vehicles certified to these bins to generate additional credits (or use fewer credits) that year.

The multipliers that manufacturers may use are found in Table IV.B.–8
below:



### TABLE 

### IV.B.–8.—M ULTIPLIERS FOR 

### A DDITIONAL 

### C REDITS FOR 

### B IN 

### 1 AND 

### 2 LDV/T

Bin Model year Multiplier

2 .................................................................................................. 2001, 2002, 2003, 2004, 2005 ................................................... 1.5 1 .................................................................................................. 2001, 2002, 2003, 2004, 2005 ................................................... 2.0

e. Interim Standards

i. Interim Exhaust Emission Standards for LDV/LLDTs
The NLEV program referenced throughout this discussion is a voluntary program in which all major manufacturers have opted to produce LDVs and LLDTs to tighter standards than those required by EPA’s Tier 1 regulations. Under the NLEV program,
manufacturers must meet an NMOG average outside of California that is equivalent to California’s current intermediate-life LEV requirement— 0.075 g/mi for LDVs and LDT1s (0.10 g/ mi for LDT2s). NLEV requirements apply only to LDVs and LLDTs, not to

HLDTs.

The NLEV program is effective beginning in the northeastern states in 1999 and in the remaining states in 2001, except that the program does not apply to vehicles sold in California or in states that adopted California’s LEV program. The program runs at least through model year 2003 and can run through model year 2005.

Under the Tier 2 phase-in we are finalizing today, not all LDV/LLDTs covered under NLEV will be subject to
Tier 2 standards in the 2004 to 2006 period. Without a program for full Tier 2 compliance in 2004 (i.e., because of the phase-in), these vehicles could
revert to Tier 1 standards. The NLEV program, moreover, is a voluntary program that contains several provisions that restrict EPA’s flexibility and that
could lead to a manufacturer or a covered Northeastern state leaving the program in or prior to 2004. To resolve these concerns we are finalizing theproposed interim program for all nonTier 2 LDV/LLDTs for the 2004–2006 model years. Our interim program will replace the NLEV program, which will
terminate at the end of 2003. The
transition from NLEV to the interim program should be smooth because the interim program will employ several bins derived from the NLEV standards for LDVs, LDT1s and LDT2s. The interim program will ensure that all LDVs, LDT1s and LDT2s that are not certified to Tier 2 levels during the 2004–2006 phase-in period remain at levels at least as stringent, on average, as NLEV levels. The interim program will also bring the emission standards

for LDT2s more into line with those for the LDVs and LDT1s by requiring that they be averaged under the same NOX standard rather than under separate

standards as is the case in the NLEV

program.

In the NPRM, we included separate sets of bins for the interim program and Tier 2 program. However, we indicated

that manufacturers could use either set for interim vehicles. In today’s final rule

we have combined all bins into one table for simplicity. We have also added two new bins having NO X values of 0.03 g/mi and 0.10 g/mi.


### 6747 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

In the NPRM, we proposed that, for LDV/LLDTs, all bins with NO X values over 0.20 g/mi would expire at the end of the 2006 model year when there are no longer any interim LDV/LLDTs.
Table IV–B.–4 shows that the two highest bins, bins 9 and 10, which were
derived from NLEV and included to
smooth the transition from NLEV to the interim program will be unuseable for LDV/LLDTs after 2006—the last year of the LDV/LLDT phase-in. Otherwise all
bins will remain viable for the duration of the Tier 2 program unless altered by another rulemaking.

We proposed to align the useful life periods for interim standards with those of the Tier 2 standards (full useful life of 120,000 miles), as discussed in
Section V.B. below. The end result of this proposal would have been that all
LDV/LLDTs—whether in the Tier 2 program or interim program—would go from 100,000 mile useful lives to 120,000 mile useful lives in 2004. However, manufacturers were extremely
concerned about the certification workload burden for 2004. They commented that they would be unable to carry any of their LDV/LLDTs over from 2003 and that they would have to recertify all of their vehicles in 2004 and then likely recertify them again as they were phased into the Tier 2 standards. Therefore, based upon comments, we are finalizing that useful lives of the interim LDV/LLDTs may remain at 100,000 miles. Our reasons for this change are discussed in greater detail in

Section V.B.

We are finalizing as proposed a corporate average full useful life NOX standard of 0.30 g/mi for this interim program. This standard is derived from the NLEV program and represents the
full useful life NO X standard in NLEV
that is associated with LEV LDVs and LDT1s. LDVs and LDT1s will already be at this level, on average, under the NLEV program. LDT2s are subject to standards that effectively impose a NOX average standard of 0.5 g/mi under NLEV, but we believe they should readily be able to meet the 0.30 g/mi average especially since they can be averaged with the LDVs and LDT1s. To aid LDV/LLDTs in meeting the 0.30 g/ mi corporate average NO X standard in the interim program, we are providing an optional NMOG value for LDT2s certifying to bin 9 (where the NOX standard=0.3 g/mi). This option is only for LDT2s, and only for those produced by manufacturers that elect to comply with the interim requirements for all of their HLDTs for the 2004 model year (see next section). The optional NMOG values for qualifying LDT2s are 0.130 g/ mi at full useful life and 0.100 at
intermediate useful life.

The 0.30 g/mi corporate average NOX standard will apply only to non-Tier 2 (interim) LDV/LLDTs and only for the 2004–2006 model years. Manufacturers will compute, bank, average, trade, account for, and report interim NOX credits via the same processes and equations described in this preamble for Tier 2 vehicles, substituting the 0.30 g/ mi corporate average standard for the 0.07 g/mi corporate average standard in the basic program. Also, EPA will condition the certificates of conformity on compliance with the corporate average standard, as described for Tier
2 vehicles. These NO X credits will be good only for the 2004–2006 model years and will only apply to the interim
non-Tier 2 LDV/LLDTs. Credits will not be subject to any discounts, and credit
deficits can be carried forward as
described under Section IV.B.4.d.vi.
above.

NMOG credits from the NLEV program can not be used in this interim program in any way. NO X credits generated under this interim program will not be applicable to the Tier 2 NOX average standard of 0.07 g/mi because of
our concern that a windfall credit
situation could occur. This could happen because credits are relatively easy to generate under a 0.30 g/mi standard compared to generating credits under a 0.07 g/mi standard. As we indicated in the preamble to the NPRM we believe the application of credits
earned under the interim standard to the Tier 2 standards could significantly delay the fleet turnover to Tier 2
vehicles. We do not believe there is a need or that it would be appropriate to allow such a delay. The requirements of the interim program will be monitored
and enforced in the same fashion as for
Tier 2 vehicles.

For the reasons cited above, we believe it is appropriate to extend interim, NLEV-like standards beyond 2003 as a mandatory program and to bring all LDVs and LLDTs within its scope. Manufacturers have already demonstrated their ability to make LDVs and LLDTs that comply at levels well
below these standards. As the interim standards for LDV/LLDTs are essentially ‘phase-out’’ standards, we did not propose and are not finalizing early banking provisions for the interim LDV/

LLDTs.

ii. Interim Exhaust Emission Standards for HLDTs

We believe these interim standards are necessary and reasonable for HLDTs. While these trucks make up a fairly small portion of the light-duty fleet (about 14%), their current standards under Tier 1 are far less stringent than the NLEV standards that apply to current model year LDVs and LLDTs. Given the delayed phase-in we are finalizing for HLDTs, we believe it is appropriate to require some interim reductions from these vehicles. Further, manufacturers have already demonstrated their ability to meet these
interim standards with HLDTs. These standards are a reasonable first step toward the Tier 2 program and will provide meaningful reductions in the
near term relative to current
certification levels under the Tier 1
emission standards.

We also proposed interim standards to begin in 2004 for HLDTs. These
vehicles are not included in the NLEV program and will be subject only to the Tier 1 standards prior to today’s rule taking effect. Tier 1 standards permit

NO X emissions of 0.98 g/mi for LDT3s and 1.53 g/mi for LDT4s. We are finalizing these standards generally as proposed; to address statutory lead time requirements, we are offering two options for the phase-in of HLDTs to the
interim standards. Manufacturers can
choose between either of these two options:

(Option 1) Like we proposed in the NPRM, manufacturers must bring their entire production of 2004 model year HLDTs under the interim requirements and phase 25% of them into the 0.20 g/ mi fleet average NO X requirement, followed by 50% in 2005, 75% in 2006, and then 100% in 2007; or

(Option 2) We are including this option to address statutory lead time requirements for HLDTs. In the case of 2004 model year test groups whose model years commence before the fourth anniversary of the signature date of today’s rule, the manufacturer may exclude those test groups from the interim HLDT provisions of the rule. In the case of 2004 model year test groups whose model years commence on or after the fourth anniversary of this rule’s signature, the manufacturer must bring all such HLDTs under the requirements of our interim program, and all such vehicles or 25% of the manufacturer’s sales of 2004 model year HLDTs, whichever is less, must comply with the corporate average NO X standard of 0.20 g/mi. The manufacturer must then bring
all of its HLDTs into the interim requirements beginning with the 2005 model year including a 50%, 75%, 100% phase-in to the 0.20 g/mi fleet average NO X standard beginning that year. The beginning of a test group’s model year is determined under section 202(b)(3) of the Act and 40 CFR Part 85 Subpart X.


### 6748 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

70 Manufacturers must cite this declaration in their LDT2 certification applications for the 2004– 2006 model years and in their LDT4 applications for the 2004–2008 model years. If manufacturers employ alternate phase-in schedules that begin prior to 2004, they must also make the declaration in each applicable year before 2004.

Our final rule is consistent with the requirements of the Act because manufacturers won’t have to phase-in HLDTs until the model year that commences four years from the signature of this rule if they don’t want to. However, to provide incentive for manufacturers to comply with the interim requirements for all of their HLDTs beginning with the 2004 model

year, i.e. to elect Option 1, we are finalizing a provision to permit those manufacturers to use higher NMOG
values in two situations. Manufacturers electing to meet the interim requirements for all of their 2004 model year HLDTs including the 25% phase-in
number must so declare in their 2004 model year HLDT certification applications. They may then:

• Use a full useful life NMOG value, through the 2008 model year, of 0.280 g/mi for LDT4s certified to bin 10 (0.195 g/mi at intermediate life); and

• Use a full useful life NMOG value, through the 2006 model year, of 0.130 g/mi for LDT2s certified to bin 9 (0.100 g/mi at intermediate life). 70

In the case of the LDT4s, the optional
NMOG standard will enable manufacturers to more easily meet our

interim HLDT NO X standards, the highest of which (0.6 g/mi) is one-third tighter than what will be required in California under Cal LEV I through 2006. For the LDT2s, the optional NMOG standard will help manufacturers certify more LDT2s to bin 9 (0.3 g/mi) than they likely would otherwise (they would probably certify
some LDT2s to bin 10 where NOX=0.6 g/mi). Therefore, both of these optional standards are consistent with our goal to achieve important early NO X benefits from our program.

Except for the application of the new option described above, the interim standards for HLDTs will apply as proposed, and will phase-in through the 2007 model year, as shown in Table IV.B.–2. We are finalizing the proposed corporate average full-life NO X standard of 0.20 g/mi for interim HLDTs. Manufacturers will comply with the corporate average HLDT NO X standard by certifying their interim HLDTs to any
of the full useful life bins shown in Table IV–B.–4. Where applicable, manufacturers will also comply with the
intermediate useful life standards
shown in Table IV.B.–5. Interim HLDTs not needed to meet the phase-in percentages during model years 2004–
2006 will have to be certified to the
standards of one of the bins in Table IV.B.–4 (and –5), and NO X will thus be capped at 0.60 g/mi. These trucks will
not be included in the calculation to demonstrate compliance with the 0.20 g/mi average.

At the end of each model year,
manufacturers will determine their compliance with the 0.20 NO X standard by calculating a sales weighted average of all the bins to which they certified any interim HLDTs, excluding those not needed to meet the applicable phase-in requirements during 2004–2006. The excluded trucks must comply with the
standards from one of the bins in Table IV-B–4 (and –5) which effectively caps their emissions at 0.60 g/mi.

For HLDT test groups that are not subject to the phase-in in model year 2004 under Option 2 above, the same requirements as described above apply except that there are no new standards
for these vehicles in the 2004 model year. Also, the optional higher NMOG
values for LDT2s and LDT4s do not apply for any manufacturer that uses Option 2.

Given that the interim HLDT standards are ‘‘phase-in’’ standards through 2007 (as opposed to the interim LDV/LLDT standards, which are ‘‘phase-out’’ standards), we are including provisions that manufacturers may employ alternative phase-in schedules as proposed for the Tier 2
standards and described in detail in section IV.B.4.b.ii. of this preamble. These schedules provide manufacturers with greater flexibility and we believe they also provide incentive for
manufacturers to introduce advanced emission control technology at an earlier date. Alternative phase-in schedules will have to provide 100% phase-in by the same year as the primary phase-in schedule (2007). Manufacturers will be eligible for alternate phase-in schedules to the extent that they produce HLDTs that meet or surpass the NO X average standard for interim HLDTs of 0.20 g/mi in 2001–2003 or to the extent that they produce more HLDTs than required that meet the 0.20 average standard in 2004
or later.

Where manufacturers elect not to meet the phase-in requirements for all of their 2004 model year HLDTs, as discussed above under Option 2, they may still employ alternate phase-in schedules, but the sum of 225 percent is required rather than the 250 percent required for alternate phase-ins
described in section IV.B.4.b.ii. In this case, the sum of phase-in percentages up through the 2005 model year must total to at least 50%. Also, manufacturers must raise the 225% value to the extent that any of their 2004 HLDTs’ model years commence on or after the fourth anniversary of the signature date of this rule and are brought into compliance with the 0.20 g/mi average NO X standard.

Lastly, note that for bin 10, which is only usable during the interim program,
we have established a PM standard of 0.08 g/mi, which is more stringent than the Tier 1 standard previously in effect for these vehicles. We do not expect low sulfur diesel fuel to be widely available during the time frame of the interim program but we expect that bin 10 levels can be reached by diesel technology on current diesel fuel. As a part of this overall approach, we are making the intermediate life standards optional for
diesels for this bin.

f. Light-Duty Evaporative Emission
Standards

We are finalizing as proposed a set of more stringent evaporative emission standards for all Tier 2 light-duty vehicles and light-duty trucks. The standards we are finalizing are shown in Table IV.B.–9 and represent, for most vehicles, more than a 50% reduction in diurnal plus hot soak standards from those that will be in effect in the years immediately preceding Tier 2 implementation. The higher standards for HLDTs provide allowance for greater non-fuel emissions related to larger
vehicle size.


### 6749 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

71 The heavy-duty definition also includes vehicles that weigh over 6000 lbs curb weight regardless of their GVWR. We are not aware that any vehicles currently produced have curb weights above 6,000 lbs, but GVWRs of 8,500 lbs or less. Nevertheless, this discussion and our requirements

includes such vehicles. 

### TABLE 

### IV.B.–9.—F INAL 

### E VAPORATIVE 

### E MISSION 

### STANDARDS

[Grams per test]

Vehicle class 3 day diurnal +hot soak Supplemental 2 day diurnal

+hot soak

LDVs and LLDTs ................................................................................................................. .................................. 0.95 1.2

HLDTs .......................................................................................................................... .......................................... 1.2 1.5

Evaporative emissions from LDVs and LDTs represent nearly half of the light duty VOC inventory projected for the 2007–2010 time frame, according to MOBILE5 projections. Manufacturers are currently certifying to levels that are, on average, about half of the current standards, and in many cases, much less than half the standards. Thus, meeting these standards appears readily feasible. Even though manufacturers are already certifying at levels much below the current standard, we believe that reducing the standards will result in
emission reductions as all manufacturers seek to certify with adequate margins to allow for in-use deterioration. Further, we believe that tighter standards will prevent ‘‘backsliding’’ toward the current standards as manufacturers pursue cost
reductions.

As mentioned in section IV.B.–4.b above, we will phase in the Tier 2 evaporative standards by the same
mechanism as the Tier 2 exhaust standards; e.g., 25/50/75/100 percent beginning in 2004 for LDV/LLDTs and 50/100 percent beginning in 2008 for HLDTs (as shown in Table IV.B.–2). As for the exhaust standards, alternative phase-in plans will also be available.

The evaporative emission standards we proposed and are finalizing today
are the same as those that manufacturers’ associations proposed during the development of California’s LEV II proposal. California ultimately opted for more stringent standards; we
believe that our standards are appropriate for federal vehicles certified on higher-volatility federal test fuel.

g. Passenger Vehicles Above 8,500
Pounds GVWR

Historically, we have categorized all vehicles above 8,500 pounds GVWR as heavy-duty vehicles regardless of their application and they have been subject to standards and test procedures designed for vehicles used in heavier work applications. 71 In the Tier 2 NPRM, we requested comment on whether some portion of vehicles above 8,500 pounds GVWR should be included in the Tier 2 program, based on vehicle use or design characteristics. The Tier 2 proposals, however, applied to light-duty vehicles and light-duty trucks and did not cover any vehicles above 8,500 pounds GVWR.

On October 29, 1999, after carefully considering all of the comments on this issue, we proposed to include all personal use passenger vehicles (both gasoline and diesel fueled) between 8,500 and 10,000 pounds GVWR in the Tier 2 program. This group of vehicles would include large SUVs and passenger vans and may include other types of ‘‘crossover’’ multipurpose vehicles in the future, depending on new vehicle designs. We proposed this Tier 2 program change in our NPRM concerning emissions standards for 2004 and later heavy-duty vehicles and engines, (64 FR 58472).

Specifically, we proposed to revise the definition of light-duty truck to include any complete vehicle between 8,500 and 10,000 pounds GVWR that is designed primarily for the transportation of persons and has a capacity of not more than 12 persons. We expected that this definition would
exclude vehicles that have been designed for a legitimate work function as their primary use, such as the largest pick-up trucks, the largest passenger vans, and cargo vans; these vehicles would continue to be categorized as heavy-duty and would be subject to applicable heavy-duty standards. We requested comment on whether the proposed definition would adequately exclude these vehicles, or whether additional criteria may be needed and how that criteria might be used.

Today, we are finalizing Tier 2 standards for passenger vehicles above 8,500 pounds GVWR. These vehicles are included in the Tier 2 program beginning in 2004 and are required to
meet the final Tier 2 standards in 2009
and later. As we intended in the proposal, these vehicles will generally be subject to the same requirements as HLDTs. We have made modifications to the program, primarily in response to comments we received in two areas: (1) Changing the definition of light-duty truck and (2) the interim program requirements.

New Vehicle Category: Medium-Duty Passenger Vehicles (MDPVs)

The mechanism we proposed to bring the passenger vehicles over 8,500 pounds into the Tier 2 program, was to modify the definition of light-duty truck to include those vehicles. The objective of this proposal was to have these
vehicles treated as HLDTs within Tier 2. We are finalizing requirements which remain consistent with our objective of including these vehicles in Tier 2 beginning in 2004. However, the approach we are finalizing is somewhat different than that proposed.

Rather than finalizing the revised definitions for light-duty truck as we proposed, we are creating a new category of heavy-duty vehicles termed ‘‘medium-duty passenger vehicles’’ (MDPVs). These vehicles will generally be grouped with and treated as HLDTs in the Tier 2 program. The MDPV category is defined along the lines of the proposed definition change for the LDT category, with some modification, as
described below. Our decision to create a new sub-category of heavy-duty vehicles rather than modify the existing LDT definition does not, in and of itself, change the way in which Tier 2 standards are applied to the vehicles.

We decided upon the above approach
because section 216 of the CAA
establishes the definition for LDT as having the meaning contained in the
CFR as of 1990. We received several comments that EPA may not change the
definition and must instead devise a way to categorize the vehicles for purposes of Tier 2 which does not change the definition of light-duty truck. Rather than adopt a change to the
LDT definition that would be questionable from a legal perspective, we are adopting an approach that we believe is clearly legally acceptable. Under this approach (as with the proposed approach), the standards for these vehicles are promulgated under


### 6750 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

72 Vehicles that are ‘‘designed’’ to accommodate more than nine passengers in the rearward seating area in their standard configuration but that have some of the standard rear seating removed to accommodate two or more wheel chair tie downs would usually not be considered MDPVs.

73 Currently, diesel heavy-duty engines are certified to heavy-duty engine standards rather than
vehicle standards. 74 ALVW is the average of curb weight and GVWR. The test weight is sometimes refered to as ‘‘half payload’’. section 202(a)(3), which applies to heavy-duty vehicles/engines.

We are defining medium-duty passenger vehicles as any complete heavy duty vehicle less than10,000 pounds GVWR designed primarily for the transportation of persons including conversion vans (i.e., vans which are
intended to be converted to vans primarily intended for the transportation of persons. The conversion from cargo to passenger use usually includes the installation of rear seating, windows, carpet, and other amenities). We are not including any vehicle that (1) has a capacity of more than 12 persons total or, (2) that is designed to accommodate more than 9 persons in seating rearward of the driver’s seat or, (3) has a cargo box ( e.g., a pick-up box or bed) of six feet or more in interior length. We would consider vehicles designed primarily for passenger use to be those that have seating available behind the driver’s seat. We have added the rear passenger seating capacity criterion to exclude large passenger vehicles which are primarily used in heavy-load passenger applications. We do not believe vehicles designed primarily for personal use passenger transportation would be equipped with rear seating for more than 9 passengers. 72

We have added the pick-up bed length criterion to the definition to clearly distinguish standard pick-ups from other vehicles meeting the GVWR and seating capacity criteria. We

received several comments that although the proposal clearly states our intention not to include heavy-duty pick-up trucks in the Tier 2 program, the proposed regulatory definition was unclear. Currently, heavy-duty pick-ups have beds in excess of six feet. Any future offerings of vehicles that are equipped with significantly shorter beds
would be included in the MDPV category, if the vehicle also met the weight and seating capacity criteria. EPA is making a distinction based on bed length because a vehicle introduced
with a shorter bed would have reduced cargo capacity and would likely have increased seating capacity relative to current pick-ups, making it more likely to be used primarily as a passenger
vehicle.

Interim Standards

As noted above, the MDPVs and
HLDTs must meet the final Tier 2 standards by 2009 at the latest. Prior to 2009, HLDTs and MDPVs are required
to meet interim standards. The interim standards, as described earlier in section IV.B.4, are based on a corporate average
full life NO X standard of 0.20 g/mile which is phased in 25/50/75/100 percent in 2004–2007. MDPVs must be grouped with HLDTs for the interim standards phase-in. We received several comments from manufacturers that requiring these larger vehicles to meet a new, unique standard prior to phase-in to the interim program would worsen the workload burden created by the Tier 2 program. Manufacturers do not currently have facilities available for chassis-testing diesel vehicles and there is not enough
time to fold diesel vehicles into a chassis-based program by 2004. 73

To address this situation, we are providing the following temporary
additional flexibilities for MDPVs. We are finalizing an additional upper bin for MDPVs for the interim program (effective in model years 2004 through 2008). This bin would only be available for MDPVs. The bin, shown in Table IV.B–10, is equivalent to the California LEV I standards that are applicable to these vehicles prior to 2004. Vehicles
certified to this bin must be tested at adjusted loaded vehicle weight (ALVW), consistent with California program testing requirements. 74 Including this upper bin provides manufacturers with the ability to carry over their California vehicles to the federal program prior to their phase-in to the interim and final Tier 2 standards. Once phased in to the interim standards manufacturers may continue to use the upper bin but the vehicles must be included in the 0.20 g/

mi NO X average. The upper bin is not
available to manufacturers for the final Tier 2 program.



### TABLE 

### IV.B.–10.—T EMPORARY 

### I NTERIM 

### E XHAUST 

### E MISSION 

### STANDARDS 

### B IN FOR 

### MDPVS a

NOX NMOG CO HCHO PM

Full Useful Life (120,000 mile) ................................................................. 0.9 0.280 7.3 0.032 0.12

Notes:

a Bin expires after model year 2008.

We proposed that HLDTs not needed to meet the phase-in percentages for the interim program during model years 2004—2006 would be required to meet one of the interim bins. Such vehicles, however, would not be included in the calculation to demonstrate compliance with the 0.20 g/mile average. Thus, we proposed that the emissions of all interim HLDTs would be capped at a

NO X value of 0.6 g/mile. We are retaining the bin structure and requirements which effectively cap NO X emissions at 0.6 g/mile for all HLDTs below 8,500 pounds GVWR, as described in section IV.B. Similarly, for MDPVs, the 0.9 g bin described above is the highest bin available and acts as the cap for vehicles not yet phased-in to the
interim standards.

In addition, for diesel MDPVs prior to 2008, we are allowing manufacturers the option of meeting the heavy-duty engine standards in place for the coincidingmodel year. Diesels meeting the enginebased standards would be excluded from the interim program averaging pool. In 2008, the manufacturers must chassis certify diesel vehicles and
include them either in the interim program or in the final Tier 2 program. In 2009 and later, all MDPVs, including diesels, must be brought into the final Tier 2 program. As with the higher bin of chassis-based standards, the purpose of this diesel provision is to provide the option of carry-over of vehicles until they are brought into the Tier 2 program. We believe these modifications to the program will substantially ease the workload

concerns of manufacturers in theinterim years by allowing them to carryover vehicle models and engine families. The provisions also remain consistent with EPA’s goal of including

the vehicles in the overall Tier 2
program structure.


### 6751 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

75 As with HLDTs, the California OBDII compliance option is available for MDPVs. 76 For Tier 2 MDPVs, evaporative standards will be 1.4 g/test for the 3 day diurnal+hot soak test and 1.75 g/test for the supplemental 2 day diurnal+hot

soak test.

77 ORVR requirements are phased in for HLDTs, at 40/80/100 percent in 2004–2006 (see 40 CFR 86.1810–01 (k)). For diesel engines that are engine certified and used in MDPVs, as allowed through model year 2007, we are requiring those engines to comprise a separate averaging set under the averaging, banking and trading requirements applicable to heavy-duty diesel engines. We are permitting engine-based certification for these diesel vehicles to provide time and flexibility for manufacturers who may have limited experience with chassis certifying vehicles containing such engines. However, we do not want to create a situation where engines above applicable engine standards could be used in these vehicles, when other MDPVs are being brought under stringent standards. Therefore we believe it is appropriate to constrain the application of credits to these engines. We note that we are not permitting credits from other programs (like NLEV) to be applied in any way to Tier 2 or
interim vehicles.

For LDT4s, we have finalized an optional higher NMOG level of 0.280 g/ mile for bin 10 (0.6 g/mile NOX), as
described in section IV.B.4.a of the preamble. MDPVs placed in bin 10 may also certify to the higher NMOG level of 0.280 g/mile. This provision provides
manufacturers with the incentive of selecting the lower NO X bin for MDPVs,
since the NMOG level is not an obstacle to compliance.

As described in section IV. B.4.e.ii., manufacturers have two options for the start of the program requirements. In Option 1, the program begins with the 2004 model year for 25 percent all vehicles. In Option 2, manufacturers can exempt 2004 model year vehicle test groups whose model years begin on or after the fourth anniversary of this rule’s signature. These options are also
available for MDPVs for the same reasons we are providing them for HLDTs. However, the additional 0.9 g bin contained in Table IV.B.–10, the optional higher NMOG standard of 0.280 g/mile for bin 10, and the option of certifying to the engine-based standards for diesels are available only with Option 1.

Other Emission Control Requirements

We are requiring all non-diesel MDPVs to be OBDII compliant beginning in 2004. California requires OBDII for their LEV I program and therefore, the new OBDII requirements are consistent with the approach of allowing vehicles to be carried over
from California. 75 Diesel vehicles which
are carried over from the California program are required to be equipped with the OBD system as the system is
certified in California. Diesel vehicles
not carried over from California are not required as part of this rulemaking to be equipped with OBDII. However, we have proposed OBDII requirements forheavy-duty diesel engines in our heavyduty engines NPRM (64 FR 58472). If OBDII requirements are finalized for heavy-duty engines and vehicles as part of that rulemaking the OBDII requirements would likewise apply to diesels in the MDPV category.

As proposed, we are applying Tier 2 evaporative emissions standards and existing HLDT ORVR requirements to MDPVs. MDPVs must be grouped with HLDTs for purposes of phasing in to the Tier 2 evaporative emission standards
contained in this rule. We have added somewhat higher standards for the MDPVs to account for their larger fuel
tanks and vehicle sizes. 76 However, the stringency of the standards remains
similar to that for HLDTs. These
standards are described in section IV.B.4.f of the preamble. ORVR requirements currently exist for HLDTs and are to be phased-in through model years 2004–2006. 77 We proposed to apply the same standards and phase-in requirements to vehicles over 8,500 pounds GVWR. We are finalizing these ORVR requirements for MDPVs, which must be grouped with HLDTs for purposes of phased-in to the ORVR requirements.

For those manufacturers electing option 2, OBD is required when the vehicle family is covered under these new requirements (i.e., 2004 or 2005 depending on when certification occurs). For ORVR, the situation is similar. The phase-in is 40 percent of any 2004 certifications which occur four years after this rule is promulgated, 80 percent in 2005, and 100 percent in 2006. As before, the vehicles covered by these phase-ins must be combined with those in the LDT3/4 phase-in for purposes of calculating compliance.

We are finalizing Cold CO and Certification Short Test requirements for Tier 2 MDPVs. However, we are not finalizing SFTP standards for MDPVs in today’s rulemaking. Currently, SFTP standards do not apply to any vehicles above 8,500 pounds GVWR, including
those in the California LEV I and LEV II programs. We are concerned, therefore, that finalizing SFTP requirements in today’s rulemaking would prevent manufacturers from carrying over vehicle models during the phase-in years of the program. We are currently contemplating a new SFTP rulemaking which would consider ‘‘Tier 2’’ SFTP standards for all vehicles, including MDPVs. California is also interested in developing more stringent

SFTP standards within the context of their LEV II program and we are coordinating with California on these

new SFTP standards.

Sustained Severe Use; In-Use Testing of

MDPVs

While we are confident that MDPVs can comply in-use with the standards we are finalizing, manufacturers are concerned about in-use liability for

MDPVs that are in sustained severe-use. In our in-use emission testing program, we generally screen vehicles for proper

maintenance and use and delete vehicles that we believe may have been misused or malmaintained. Also, in the regulations for manufacturer in-use testing, we permit manufacturers to delete vehicles from samples if they have been used for ‘‘severe duty (trailer towing for passenger cars, snow plowing, racing)’’, and we provide that vehicles may be deleted for other reasons upon EPA approval.

We recognize that MDPVs will be marketed and used for carrying many passengers, carrying heavy loads and trailer towing. While it is not our intention to exempt vehicles from in-use liability that have been used for their intended purposes, we understand that some MDPVs may be subject to sustained severe service applications, such as frequent overloading or frequent towing beyond manufacturer’s advertised capacity and could not be considered to be representative of properly maintained and used vehicles. Furthermore, we would not necessarily consider to be representative MDPVs which are routinely or regularly used in heavy-load hauling application or towing even within the manufacturers limits. Thus, for example, an SUV MDPV used on a daily basis to haul a work crew and tow equipment to a distant work site may not be representative while the same SUV used to haul the family and tow a boat to the
lake on weekend excursions would be representative. MDPVs in sustained severe operations should not be
included in manufacturer or EPA in-use test programs, while those that see less frequent severe operation should be
included.


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C. Our Program for Controlling Gasoline Sulfur

As with our program for vehicles, the program we are establishing today for reducing sulfur levels in commercial gasoline will achieve the same large

NO X reductions that we projected for the proposed program. Here, too, the final program is very similar to our proposed program. Adjustments we have made to the proposed program will smooth the refining industry’s transition to the low-sulfur requirements and encourage earlier introduction of
cleaner fuel.

With today’s action, we are requiring substantial reductions in gasoline sulfur levels nationwide. As we explained in Section IV.A, because sulfur significantly inhibits the ability of automotive catalysts to control emissions, we had to consider sulfur’s impact in setting the Tier 2 standards. We knew at the time of proposal that newer catalysts were more sensitive to sulfur than older technologies, and projected that Tier 2 catalysts would be
as or even more sensitive than those used in today’s NLEV vehicles. Furthermore, we believed that the sulfur build-up on Tier 2 catalysts may be irreversible. Since the proposal,
additional data we’ve collected have confirmed and strengthened our concerns. It now appears that the catalysts expected to be used in Tier 2
vehicles will be even more sensitive to sulfur than we originally estimated, and that this sulfur impact will be approximately 45 percent irreversible under typical driving conditions. Thus, the gasoline sulfur standards we finalize today will enable the stringent tailpipe emission standards we’re implementing for Tier 2 vehicles and will help to
ensure that these low emission levels will be realized throughout the life of the vehicle. Furthermore, since vehicles already on the road, including NLEV vehicles, are in many cases quite sensitive to sulfur, gasoline sulfur control will also help to reduce emissions of pollutants that endanger public health and welfare from these
vehicles.

In developing this gasoline sulfur control program, we gave substantial consideration to the ability of the refining industry to meet these requirements. We proposed a set of standards applying to refiners and to
individual refineries combined with a sulfur averaging, banking, and trading (ABT) program intended to provide flexibility in meeting the standards. We concluded that our proposal was
reasonable and cost-effective based on our projections regarding the number of refineries that would (1) need to reduce sulfur levels each year as the standards tightened, (2) need sulfur ABT credits to meet the 30 ppm refinery average
standard in 2004 and/or 2005 to defer
installation of desulfurization equipment, and (3) install desulfurization equipment prior to 2004, generating the needed sulfur credits. This analysis formed our picture of the industry’s investment stream—a year-by-year estimate of how many refineries would be constructing new equipment and what technologies these
refineries would choose. We assumed that any investments would be in the new, lower cost technologies, and that these technologies would be available and adequately demonstrated to allow refiners to select them as early as the year 2000 to begin operation (and thus, credit generation) as early as 2002. Based on these assumptions, our analysis showed that sufficient credits would be generated before 2004 to enable a number of refineries to delay
construction and use credits to meet the 30 ppm standard in 2004, and in some cases, even in 2005. Overall, we believed our analysis represented a
reasonable and balanced rate of investment by the industry over a several year time period.

In response to our proposal, we received many comments which raised concerns about the feasibility of our program. Some comments suggested that our proposed declining cap (300 ppm cap for 2004 and a reduced cap of 180 ppm for 2005) could be an additional and burdensome expense for most refiners to meet. Specifically, these commenters believed that the declining cap would be more constraining than compliance with the corporate average or even the refinery average standards (as long as the ABT program produced sufficient credits). Because refiners probably would not make multiple investments in such a short time, the 180 ppm cap could force some refiners to install the equipment needed to get to the 80 ppm cap earlier than otherwise needed. The commenters argued that this would force all of the industry’s investments into the first years of the program rather than allowing for a smoother transition over several years as we had originally envisioned. Many comments also suggested that since there have not been long-term
commercial demonstrations of the newer gasoline desulfurization technologies, refiners would not consider these technologies to be viable and, if faced with our proposed 30 ppm standard in 2004, may select the more traditional, higher cost sulfur reduction processes. Some of these commenters suggested that we should delay the 30 ppm standard, and recommended a range of suggested deadlines (2005– 2007).

We also received many comments which suggested that the ABT program restricted the generation of credits, and provided no certainty that credits would be generated prior to 2004. Commenters stated that two features in particular— the delay in establishing each refinery’s
sulfur baseline due to 1997–98 data review and the strict 150 ppm ‘‘trigger’’ for generating credits—caused them to question whether adequate sulfur
credits would be available. If credits could not be guaranteed early enough to forestall investment decisions, refiners would be forced to begin construction earlier than we had projected. Under such a scenario, the costs of the program would be substantially greater, and many commenters suggested that, regardless of cost, it would be impossible for the entire industry to meet the deadline (due to limitations on engineering design and construction resources as well as the time required to obtain permits).

Finally, we received many comments which argued that not all refineries would be able to concurrently comply with the proposed standards in the time period provided, given the competition for engineering resources and the time
needed for construction of desulfurization equipment. These comments focused specifically on small refineries (owned by both small and large corporations) and refineries that were relatively isolated geographically (such as many refineries in the Rocky Mountain region) which had little access to other sources of gasoline should they have difficulty in complying with our requirements. The commenters generally argued that these
refiners needed more time than the rest of the industry to meet our proposed
standards. Some of the commenters also argued that the standards applicable to many of these refiners should be less stringent because of their belief that the
environmental needs of the states where
these refineries were located and/or marketed gasoline were small relative to the needs of other states. Suggestions for temporary and permanent regional programs which provided less stringent
control in the Western half of the country were included with many of
these comments.

Based on what we’ve learned from the
comments received and additional information we’ve gathered, we have revised our analysis of when refiners will invest in desulfurization equipment and how the sulfur ABT program can


### 6753 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

best help to distribute these investments over several years while maintaining the original goals of the program. The following is a brief summary of our new analysis; a more complete explanation of our assumptions can be found in the

RIA.

About 15 percent of current domestic gasoline production already meets the gasoline sulfur standard, or can do so with very little additional capital investment, and at most a small increase in operating cost. The remainder of the industry—the majority of U.S.
refineries—will have to install at least one desulfurization processing unit to lower gasoline sulfur to the required levels. Furthermore, many of these refineries will need to make changes to their operations in advance of 2004 simply to comply with the 300 ppm cap standard, even if they can obtain sufficient ABT credits to delay compliance with the 30 ppm refinery average standard. Refiners facing this
situation will need to make their decisions within a year or at most two from today’s action. From the comments
we received and discussions we’ve had with refiners and technology vendors, we acknowledge that some of the newer, more promising processes may not be in operation for sufficient time to gain valuable operating experience (one to two years of operation) until 2002 or later. Hence, we now believe that some refiners may choose from one of the traditional, commercially-demonstrated desulfurization processes, even though these technologies may be more costly,
to meet our standards.

However, we continue to believe that the majority of refiners will delay construction (taking advantage of the sulfur ABT program and perhaps making modest operational changes in the interim) and will have a wide range of technological options to choose from, at reduced capital investment and operating costs compared to the more traditional approaches. Examples of these technologies are CDHydro and CDHDS (licensed by the company CDTECH), Octgain 125 and Octgain 220 (licensed by Mobil Oil), S Zorb (licensed by Phillips), IRVAD (licensed by Black & Veatch), and others. These technologies generally use conventional refining processes combined in new ways, with improved catalysts and other design changes that minimize the undesirable impacts (such as a substantial loss in octane) and maximize
the effectiveness of the desulfurization approach. Since these processes provide less costly ways to reduce gasoline sulfur, we have based our economic assessment (summarized in Section IV.D. below) on the presumption that the majority of refiners will elect to use one of these processes to meet the 30 ppm standard, even if it requires delaying compliance (through the purchase of ABT program credits) until

2006.

However, after considering the data available to us about current refinery sulfur levels and the ability of refiners
to reduce sulfur levels to meet the standards, we have made several modest changes to the program. These changes
will not affect the environmental performance of the proposed program. We agree that the declining cap had the unintended consequence of forcing
investments earlier than desired for an orderly transition to the 80 ppm cap. Thus, we have changed the program from the proposal, establishing a 300 ppm per-gallon cap in 2004 and 2005. We do not expect this change to have an impact on the environment (or on the
Tier 2 vehicles that will be introduced in this interim period) since average sulfur levels will be required to decrease due to the declining corporate average, which begins in 2004. We kept the corporate average standards proposed for 2004 and 2005, but are permitting inter-company trading around these standards. We believe this change will provide further flexibility to the industry in allowing some refineries to delay construction and encourage others to move forward sooner. Having now concluded that many refiners would benefit from an additional year to evaluate and consider the technological options before having to install equipment to meet the 30 ppm standard, we have delayed this standard for one year. In acknowledgment that some areas of the country have less urgent
environmental needs for the emissions reductions that this program will bring, and that many of the refiners that supply gasoline to these areas are ones which will have the most difficulty in meeting the standards, we have finalized a geographic phase-in of the standards to complement the temporal phase-in applicable to the rest of the industry. Thus, in certain states in the West, refiners have the option of meeting interim standards while delaying compliance with the 30 ppm average until 2007. Finally, we have made changes to the sulfur baseline requirements and the credit trigger to help ensure that the sulfur ABT program functions as we originally envisioned it
would.

These changes will encourage reductions in gasoline sulfur levels beginning as early as 2000, while providing enough flexibility to require the majority of refineries to meet a 30 ppm average sulfur standard by 2006. Overall, the industry will be able to spread the needed investments over several years rather than having to comply as a whole by 2004, and will be

able to maximize the use of the most efficient and lowest cost technologies. While we have provided additional flexibility for the industry, we have done so without compromising the environmental benefits of the program in 2004 and beyond when compared to our proposal.

The following sections summarize the requirements for gasoline refiners and importers, including our geographic phase-in requirements; special provisions for small refiners, and our plans to facilitate the construction permitting process to enable refiners to install gasoline desulfurization technology in a timely manner. Section VI provides additional information about the compliance and enforcement provisions that will accompany these requirements. More detailed information in support of the conclusions presented here is found in

the RIA and in our RTC document.

1. Gasoline Sulfur Standards for Refiners and Importers

This section explains who must comply with the gasoline sulfur control requirements, the standards and deadlines for compliance, and how refiners can use the ABT program to

meet the standards. The last section discusses how individual state gasoline sulfur programs are affected by today’s action. Standards specific to eligible small refiners are presented in Section

IV.C.2.

a. Standards and Deadlines that Refiners/Importers Must Meet

Anyone who produces gasoline for sale in the U.S. must comply with these regulations. This includes anyone meeting our definition of a refiner (including blenders, in most instances) and importers. Certain refiners may qualify for temporarily less stringent

standards and deadlines because these companies either (1) market gasoline in the temporary geographic phase-in area (explained in section b below), or (2) they qualify under our definition of small refiner (explained in section IV.C.2 below). Foreign refiners may also have separate requirements, if they qualify as small refiners.

These requirements will apply to all gasoline sold in the U.S., including Alaska, Hawaii, Puerto Rico, American Samoa, the Virgin Islands, Guam, and


### 6754 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

78 Gasoline sold in California is exempt from meeting these Federal standards, due to our belief that California gasoline already meets or exceeds these requirements. See Section VI for more

discussion on this issue. 79 Including gasoline produced for use in the geographic phase-in area and small refiner gasoline. the Northern Mariana Islands. 78 This national approach is appropriate, based
on our conclusions that vehicle
emissions must be reduced nationwide to adequately protect public health and
the environment and Tier 2 vehicles require protection from the harmful impacts of gasoline sulfur regardless of where they are operated.

Table IV.C.–1. summarizes the standards for gasoline refiners and importers. There are three standards which refiners and importers must meet. In 2004 and beyond, every gallonof gasoline produced is limited by a pergallon maximum or ‘‘cap.’’ The cap standard becomes effective January 1, 2004 (and January 1 of subsequent years as the cap standard changes). Also, in 2004 and 2005, each refiner must meet an annual-average standard for its entire corporate gasoline pool. Finally, each individual refinery is subject to a refinery average standard, beginning in

2005. Refineries that do not take advantage of the sulfur ABT program will have actual sulfur levels averaging 30 ppm beginning in 2005. Additional details about the requirements for meeting these standards is found in the following sections.



### TABLE 

### IV.C.–1.—G ASOLINE 

### S ULFUR 

### STANDARDS FOR 

### R EFINERS 

### , I MPORTERS



### , AND 

### I NDIVIDUAL 

### R EFINERIES

[Excluding Small Refiners and GPA Gasoline]

Compliance as of— 2004

a 2005 2006+

Refinery Average, ppm b

.......................................................................................................................... ..... ............... 30 30 Corporate Pool Average, ppm c ............................................................................................................... 120 90 ...........

......... Per-Gallon Cap, d ppm ............................................................................................................................ . 300 300 80

NOTES:

a We project that the pool averages will actually be below 120 ppm in 2004. For a discussion of how the program gets early sulfurreductions before 2004, see section IV.C.1.c.

b The refinery average standard can be met through the use of sulfur credits or allotments from the sulfur ABT program, as long as the applicable corporate pool average and per-gallon caps are not exceeded, as explained in Section IV.C.1.c.viii.

c. The corporate pool average standard can be met through the use of corporate allotments obtained from other refiners, if necessa ry, as explained in Section IV.C.1.c.iii.

d In 2004, exceedances up to 50 ppm beyond the 300 ppm cap are allowed. However, in 2005, the cap for all batches will be reducedby the magnitude of the exceedance.

i. What Are the Per-Gallon Caps on Gasoline Sulfur Levels in 2004 and Beyond?

To reduce the potential for permanent damage to the emission controls of Tier 2 vehicles and later NLEV vehicles, we are implementing caps on the sulfur content of every batch of gasoline produced or imported into the country beginning in 2004. As shown in Table IV.C.–1, a cap of 300 ppm is first implemented in 2004. This cap remains in 2005. In 2006 and beyond, the cap is lowered to 80 ppm. These caps apply at the refinery gate. Sulfur caps are also applied to gasoline downstream of the refinery; see Section VI for additional discussion of downstream cap standards. These downstream caps will facilitate compliance and enforcement without changing the way the distribution system currently functions.

Several commenters suggested the rule should also include a provision to
address the occasions when refiners must temporarily take processing units out of operation so that planned, recurring maintenance can be performed, commonly termed ‘‘turnarounds,’’ or if processing units are unexpectedly taken out of operation due to accident or malfunction, commonly termed ‘‘upsets.’’ These commenters expressed particular concern that the gasoline produced at a refinery may not meet the sulfur cap standards when a refinery’s desulfurization unit is not operating. These commenters contended that the regulations should allow refiners to produce gasoline that exceeds the cap standard for a limited
time where the excess sulfur is due to a turnaround or upset. However, they also suggested that the refiner should be required to meet the refinery average standard with the high sulfur gasoline included in its average calculation in
order to create an incentive for refiners
to limit the volume and sulfur content of high sulfur gasoline.

Today’s rule does not grant relief to
refiners because of turnarounds or upsets. While the concern raised by the commenters is reasonable, the solution they suggested would nevertheless result in distribution of gasoline exceeding the cap standards. The cap standards are necessary because gasoline with higher sulfur levels will significantly harm or destroy the
emission controls used in Tier 2
vehicles.

We believe there are strategies refiners can use to mitigate or eliminate the
difficulties associated with turnarounds and upsets. For example, some refiners
schedule turnarounds for a number of refinery processing units at the same time when the refinery largely stops producing gasoline, thereby avoiding the need to produce any high sulfur gasoline. In other situations it may be possible for a refiner to store high sulfur products until the desulfurization unit is operating or to transfer high sulfur products to a neighboring refinery for

desulfurization.

We commit to continue evaluating the turnaround issue especially as new technologies are introduced. Based on our evaluation, if a problem is evident and if an appropriate solution can be devised, we will act at that time.

In 2004, if any batch of gasoline 79 exceeds the 300 ppm cap (up to 350 ppm), then the cap for all batches produced by the refinery in 2005 will be reduced by the magnitude of the exceedance. For example, if any given batch of gasoline has a cap of 325 ppm (a 25 ppm exceedance) in 2004, then the cap becomes 275 ppm for all batches of gasoline produced by that refinery in
2005. However, at no time in 2004 can a batch be higher than 350 ppm sulfur. We have made this adjustment to

accommodate those refiners who would have to invest in control technologies to meet the 300 ppm cap in 2004 (perhaps at a higher cost than they would incur if they could delay the investment a year) but could otherwise meet a slightly higher cap through operational changes which would not require new equipment.


### 6755 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

ii. What Standards Must Refiners/ Importers Meet on a Corporate Average

Basis?

Refiners and importers must meet annual-average, volume-weighted sulfur standards for their entire corporate gasoline pool in 2004 and 2005. In 2004, this standard is 120 ppm; in 2005, it is reduced to 90 ppm. In 2006 and beyond, there will no longer be a corporate pool average standard, since each refinery and importer will be held to its own single refinery average standard, as
discussed in the next section.

These standards represent the maximum allowable sulfur levels, on an annual average basis, for each refiner/ importer, volume-weighted across all refineries owned and operated by that refiner (or all gasoline imported by the importer in the calendar year), rather than at each individual refinery or by each batch of gasoline. Thus, a refiner’s gasoline may exceed the average standard of 120 ppm at one refinery, if sufficient gasoline below that standard is produced at its other refinery(ies),such that its corporate, volumeweighted average sulfur level does not exceed 120 ppm. Alternatively, allotments may be used to meet this requirement. This requirement does not apply to small entities or to corporations that do not have to meet the pool average standard in the GPA program. For compliance with this corporate averaging requirement, as well as with the other requirements of this subpart, we consider a parent corporation owning wholly-owned subsidiaries that
also own refineries to be the refiner of these facilities. Thus, the parent corporation must comply with refiner corporate average requirements. In its compliance calculations, the refiner must include the gasoline produced at the refineries it owns, plus the gasoline produced at the refineries owned by its wholly-owned subsidiaries.

For purposes of compliance, we proposed that a joint venture, in which two or more refiners collectively own and operate one or more refineries, be treated as a separate refining corporation under the gasoline sulfur requirements. Hence, a refinery owned by a joint venture would have been included in the corporate pool calculations of the joint venture, and
could not have been included in calculations with other refineries solely owned by one of the parties to the joint
venture. Based on comments we received on this issue which argued that a company with majority ownership in the joint venture should be allowed to count the jointly held refinery in its corporate average, we have revised our treatment of refineries owned by joint ventures. Each joint venture must separately meet the corporate pool average standard, whether the joint venture owns one or multiple refineries. If a joint venture fails to meet the corporate pool average standard, then each partner in the joint venture is jointly and severally liable for the violation. However, if one partner to a joint venture refinery includes the joint venture refinery in its corporate pool, and that corporate pool meets the corporate pool average standard, then the joint venture will be considered by EPA to be in compliance (if the joint venture owns only the one refinery). If the joint venture owns multiple refineries and only one or some of the refineries is included in the corporate pool calculations of one partner, compliance by the joint venture with the corporate pool average standard will be judged based on the average sulfur levels of the remaining refinery(ies) owned by the joint venture.

In meeting the corporate average stds in 2004 and 2005, refiners and importers may use allotments as
discussed in IV.C.1.c below.

iii. What Standards Must be Met by Individual Refineries/Importers?

Beginning in 2005, every refinery must meet an average standard of 30 ppm sulfur at the refinery gate on an annual, volume-weighted basis. Similarly, every importer must meet the 30 ppm average standard beginning in 2005. (These requirements do not apply to small entities or to GPA gasoline). In meeting this standard, individual refineries and importers may use credits generated or purchased under the provisions of the sulfur ABT program discussed below in Section IV.C.1.c, and/or, in 2005 (only), sulfur allotments (as described in the previous section)
obtained from a refiner who has excess allotments to sell, if they are unable to comply based on their actual gasoline sulfur levels. Hence, the actual average sulfur levels for gasoline produced at some refineries can be higher than 30 ppm in 2005, but only if refiners use (1) credits generated from cleaner gasoline produced early and/or (2) allotments generated by a refiner which produces gasoline averaging, on a corporate basis, lower than 90 ppm in 2005. However, the corporate pool average standards and per-gallon caps will limit the degree to which gasoline can exceed 30 ppm on

average.

We allow refiners to use either sulfur
allotments or ABT credits to meet the 30 ppm standard in 2005 for several reasons. First, this is an environmentally neutral approach because the national pool in 2005 will still average no greater than 90 ppm, since every refiner must meet the corporate average standard before applying allotments to the compliance of any refineries with the 30 ppm standard. Second, it provides refiners
who have excess allotments in 2005 an additional market for those allotments, thus giving refiners an incentive to exceed the 90 ppm corporate average standard in 2005. In either case, the
reductions will have occurred and thus the allotments and credits have very similar purposes and thus should be interchangeable.

In 2006 and beyond, the 30 ppm refinery average standard continues to be a requirement for every refinery or importer. The sulfur credits generated in the ABT program may be used by refineries or importers to comply with this requirement. However, because of the 80 ppm cap in these years, we expect that the majority of refiners/ importers will average 30 ppm, although some individual refineries/importers could average slightly more or less (if the refineries/importers bank, sell, or purchase credits to meet this standard, as explained in the ABT discussion below). Furthermore, the majority of credits will expire at the end of 2006.

b. Standards and Deadlines for Refiners/ Importers Which Provide Gasoline to the Geographic Phase-In Area (GPA)

As indicated above, certain refiners may qualify for temporarily less stringent standards and deadlines for some or all of their gasoline because these companies either (1) produce gasoline to be sold in the temporary geographic phase-in area (GPA) or (2) qualify under our definition of small refiner. In this section, we explain the geographic phase-in area of our program
and the interim standards and deadlines for compliance in that area. The provisions that apply to qualifying small refiners are described in section IV.C.2.,
below.

i. Justification for Our Geographic Phase-In Approach

In addition to phasing in our national gasoline sulfur program temporally from 2004–2006, we are phasing in our program geographically. In response to our proposal, we received many comments from the refining industry regarding timely implementation of our proposed gasoline sulfur program. Commenters argued that not all refineries would be able to concurrently comply with the proposed standards in the time period provided, given the competition for engineering resources
and the time needed for construction of


### 6756 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

80 Much of this gasoline is produced by small volume refineries that are not owned by small
businesses, and are therefore not afforded the flexibility of the small refiner provisions described

in Section IV.C.2. 81 Alaska, Colorado, Idaho, Montana, New Mexico, North Dakota, Utah, and Wyoming desulfurization equipment. In consideration of these comments, we
have made some modifications to enhance the timing of our program without compromising the environmental benefits we expected from our proposal.

As part of our assessment we also examined other phase-in approaches which might enhance the orderly introduction of refining technology without jeopardizing the environmental benefits of our program. As a result of this assessment, we have concluded that many states in the Great Plains and Rocky Mountain areas of the United States have a somewhat less urgent environmental need for ozone precursor reductions in the near term. Moreover, their gasoline supply is dominated by that produced by small capacity, geographically-isolated refineries located therein. As a general rule,
refineries in this area will have the most
difficult time of all refineries nationwide in competing for the vendor, supply, engineering, and construction resources needed to modify their refineries to comply with the standards. Based on 1998 Department of Energy data, over 80 percent of the gasoline sold in this area is produced by the relatively small refineries located within the region. 80 Similarly, Alaska faces a less urgent environmental need for reductions in ozone precursors and has refineries which are challenged and geographically isolated.

A more orderly and cost-efficient phase-in of the 30 ppm standard could be achieved if all gasoline sold in this area was subject to somewhat less stringent standards than those in the rest of the country for a short time. This approach will allow the refineries producing gasoline for use in this area more compliance flexibility, more time to install and prove out the equipment needed for compliance, and thus a greater opportunity to reduce their overall costs. As described below, this approach results in only a minimal loss in emission reduction benefits. By stretching out demand for design, engineering, construction and other related services during the 2000–06 period, these provisions should also help to reduce the overall costs of the gasoline sulfur program.

The remainder of this section is divided into two parts. The first describes the rationale for development of this approach and how we identified the appropriate area, and the second provides a description of the requirements for refiners and importers that produce fuel for sale in the area.

ii. What Is the Geographic Phase-in Area (GPA) and How Was it Established?

As we considered the geographic phase-in approach, we aimed to
minimize the environmental losses which could occur from exposing Tier 2, NLEV, (and other) vehicles to higher gasoline sulfur levels when the gasoline sulfur standards are being phased in
nationwide. We used two criteria to develop and evaluate this approach: (1) relative environmental need and (2) the ability of U.S. refiners and the distribution system to provide compliant gasoline.

The states we have identified for the GPA are shown in Figure IV.C–1. 81

BILLING CODE 6560–50–P

BILLING CODE 6560–50–C

The first and primary criterion we considered in defining this area was environmental need. In defining the GPA, we identified those states that have somewhat less urgent
environmental need in the near term for reductions in ozone precursors and whose emissions are less important in terms of ozone transport concerns. This
area includes some states that are located in the Great Plains and the Rocky Mountains, as well as Alaska. Most states within the Rocky Mountains

and Great Plains do not have a compliance problem with the 1-hour ozone standard in the near term, although they do have concerns in terms of maintaining compliance with the particulate matter standard. However, there are two states (Arizona and Nevada) in the Rocky Mountain vicinity that do have ozone air quality concerns.

These states have instituted local fuel quality programs (in Phoenix, AZ and Las Vegas, NV) to reduce ozone precursor emissions. In addition, as shown in Table III.C–2, Arizona and Nevada are projected to have concerns with PM10 compliance in the future. Given these factors, we excluded them


### 6757 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

82 As discussed below, refiners can supply gasoline not designated as GPA gasoline to the GPA, provided it meets the standards in Table IV.C.–2. Also, the GPA standards do not apply to gasoline produced by small refiners that is used in the GPA. from the phase-in area and its temporarily less stringent standards except as described below in Section
IV.C.1.b.vii for counties and tribal lands in adjacent states.

We also defined the phase-in area based on the relative difficulty of producing or obtaining complying gasoline. The refining industry in the GPA is dominated by relatively low capacity, geographically-isolated refineries many of which are owned by independent companies. Such refineries face special challenges in complying with the requirements of the national program by 2004 because their crude capacity, corporate size, and location make it difficult for them to compete for the design, engineering, and
construction resources needed to comply by 2004.

Furthermore, an assessment of 1998 gasoline production and use data and information on the products pipeline system shows that states in the GPA and portions of several adjoining states are solely or predominantly dependent on gasoline produced by these refineries
and have limited or no access to gasoline from other parts of the country. Based on this analysis, we concluded that several states and portions of other states meeting our first criterion (less urgent environmental need for ozone precursor emission reductions) also face the likelihood of a supply shortage of low sulfur gasoline. Providing low sulfur gasoline to these states and adjoining areas is expected to be more difficult and costly in the near term. Section IV.C.1.b.vii below, discusses how the adjoining areas (counties/tribal lands) will be identified.

Thus, we believe it is appropriate to phase in the 30 ppm average, 80 ppm cap standards in these areas by allowing an additional year compared to the rest of the country, rather than delaying implementation of the standards
nationwide to accommodate these states. Under this approach, the areas with the most urgent need for the ozone
reduction benefits associated with low sulfur gasoline will realize them as soon as is feasible, and other areas will experience them shortly thereafter.

On the other hand, much of the area in the adjoining states has significant pipeline, rail, barge, and truck access to gasoline which will be capable of meeting the standards in Table IV.C–1 beginning in 2004. Even if these states
have less environmental need in the near term, there are health benefits (particulate and air toxic emission reductions) as well as performance
benefits for vehicle emission control systems (including avoidable irreversible sulfur effects) which need not be foregone. Therefore, we
concluded that since it will not be more difficult to send gasoline to these adjoining areas through the distribution system, the significant environmental benefits of requiring low sulfur gasoline as early as is feasible justifies excluding
these states from the GPA.

Some might argue that there are other
states which should be considered under this program. However, based on
our criteria of environmental need (including ozone transport and irreversibility concerns) challenged refineries, and limited access to complying gasoline we could identify
no other states or territories which to
include.

iii. Standards/Deadlines for Gasoline Sold in the Geographic Phase-in Area

While the states in the GPA may have
less of an environmental need for ozone precursor reductions in the near term, there are significant environmental reasons to make the program as stringent as possible, still enabling a smooth transition to low sulfur gasoline nationwide. Toward that end, we are establishing the following requirements for gasoline sold in the GPA, which we view as the appropriate balance between
these two factors.

The GPA provision covers all gasoline produced or imported for use in the GPA, whether refined there or brought in by pipeline, truck, rail, etc. 82 Foreign refiners are involved in this program through the importers, who are, in fact, the regulated entities. Refineries and importers must meet a 150 ppm average and a 300 ppm cap for all gasoline produced or imported for the GPA under this program beginning January 1, 2004. However, if a refinery’s/importer’s 1997–98 average sulfur level is less than 150 ppm, then that refinery’s/importers gasoline has a standard of its baseline plus 30 ppm but in no case greater than 150 ppm. For example, a refinery with a baseline of 100 ppm would have a sulfur standard of 130 ppm for its GPA gasoline, a refinery with a baseline sulfur level of 140 ppm would have a standard of 150 ppm for its GPA gasoline, and a refinery with a baseline of 200 ppm would have a standard of 150 ppm for its GPA gasoline. Furthermore, if under the ABT provisions discussed below and in section IV.C.1.c, a refinery/importer generates credits (in 2000–2003) and/or allotments (in 2003) by dropping its refinery/imported gasoline average below 150 ppm then the baseline for that refinery is set at the new level and the standard becomes baseline plus 30 ppm but not greater than 150 ppm. This is to ensure that refineries and importers who already are lower than the 150 ppm standard on average maintain current sulfur levels. The 30 ppm factor is intended to allow some flexibility for refineries and importers whose 1997
and 1998 levels are an aberration from normal operations or who face changes in crude slates in future years.

Corporate pool average standards apply in the national gasoline sulfur program for calendar years 2004 and 2005. Most refiners/importers producing gasoline for use in the GPA market the majority of their gasoline outside of the GPA where they compete with many other refineries. Since the phase-in of the national program expects compliance with the 120/90 ppm corporate pool average standards in 2004 and 2005, we are requiring that refiners/importers who market the majority (greater than 50 percent of production volume) of their gasoline
outside of the GPA to account for the sulfur levels of their GPA gasoline in their calculation for compliance with the corporate pool average standards.

To provide additional flexibility during this phase-in, refiners may use sulfur ABT credits and allotments (as explained in IV.C.1.c) to meet these standards. Refineries producing GPA gasoline can generate credits beginning in 2000 under the provisions of the national program (described in section IV.C.1.c). Also, refineries/importers marketing gasoline in the GPA may through extraordinary measures be able to generate credits in 2004–2006. To qualify they must achieve levels below 150 ppm or their more stringent
baseline levels as discussed above
whichever is less. Under these circumstances, these refineries/ importers can earn credits for the GPA gasoline they produce during 2004–06. Credits generated under the GPA program are fully fungible with national credits and are subject to the same regulatory requirements.

The national program includes provisions which permit refiners/ importers to generate allotments for use
in 2004 and 2005. Refiners and importers marketing gasoline in the GPA may only generate sulfur
allotments in 2004 or 2005 if their corporate average sulfur level meets the corporate pool average standards for each year (as indicated in Table IV.C.1), including gasoline produced for the GPA, if applicable. Refiners not compelled to meet the corporate pool


### 6758 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

83 These segregation and designation requirements do not apply to gasoline produced by refiners subject to the small refiner standards

described in Section IV.C.2. This is because small refiner gasoline can be sold anywhere in the country, and is not subject to different standards depending on where it is sold. average standards under the GPA may not generate allotments.

The temporary provisions for the GPA apply for three years, 2004 through
2006. Since the low sulfur standards for the rest of the country require compliance with a 30 ppm refinery average standard and an 80 ppm gallon cap in 2006, the geographic phase-in provides an additional year to reach those standards. This extra year and the somewhat less stringent standards during the phase-in will provide the refining industry the opportunity for more orderly transition to the 30/80 ppm standards by 2007.

Requirements for gasoline sold in the GPA are summarized in Table IV.C.–2, below. Gasoline produced by refiners subject to the small refiner standards described in Section IV.C.2. of this notice is not subject to the provision of the geographic phase-in, since the small refiner provisions apply to eligible refiners regardless of geographic location. Gasoline produced by such refiners can be sold nationwide, including in the GPA.



### TABLE 

### IV.C.–2.—G ASOLINE 

### S ULFUR 

### STANDARDS FOR THE 

### G EOGRAPHIC 

### P HASE 

### -I N 

### A REA

[Excludes Small Refiners]

Compliance as of— 2004 2005 2006

Refinery GPA Gasoline Average a , ppm ................................................................................. 150 150 150. Corporate Pool Average b , ppm ............................................................................................... 120 90 Not Applicable. Per-Gallon Cap c , ppm ............................................................................................................ 300 300 300.

Notes:

a The refinery average standard for GPA gasoline is the more stringent of: 150 ppm; the refinery 1997–1998 baseline plus 30 ppm; or the sulfur level from which early credits were generated plus 30 ppm. Refiners can use credits or allotments to meet the average.

b Applies only to refiners/importers which sell >50% of their gasoline outside the GPA.

c As discussed above, in 2004 both GPA and Non-GPA gasoline may have a sulfur content as high as 350 in which case the refinery o r importer becomes subject to a correspondingly more stringent cap standard in 2005.

iv. What Are the Per-Gallon Caps on Gasoline Sulfur Levels in the Phase-in

Area?

The sulfur level caps for gasoline sold in the phase-in area and the rest of the nation are the same in 2004 and 2005, but in 2006 the cap remains at 300 ppm in this area while it declines to 80 ppm for the rest of the country. To assure that compliance at the refinery gate is correct regardless of where the gasoline is ultimately sold, as gasoline intended for
the GPA moves in the distribution system to or through the geographic area it must be identified as phase-in area gasoline in product transfer documents and must remain segregated from gasoline intended for use outside this area. In addition, use of phase-in area gasoline is prohibited outside the GPA, but the converse is allowed, i.e., gasoline designated for use outside the
GPA can be used in this area. For all three years, refiners and importers must meet the requirements described in Tables IV–C.1 and IV–C.2, as applicable, and therefore must maintain refinery or import records as applicable as to where a gasoline batch is sold. 83

We recognize that this higher standard/cap for one year could create the incentive for those not marketing gasoline in the GPA today to seek a market to sell higher sulfur gasoline and
for others to seek to increase market
share. While this is indeed allowable under our program and is perhaps to be anticipated in a free market system, in
all likelihood the incentives are small. Such refiners/importers would still have to meet the 150 ppm average and would perhaps face increased shipping and marketing costs. Nonetheless, we plan to monitor market developments to assess whether such a provision creates significant market shifts or the potential for increases in average sulfur levels in the GPA gasoline.

v. How Do Refiners/Importers Account for GPA Fuel in Their Corporate Average Calculations?

Those refiners or importers that sell all of their gasoline to the GPA (i.e., they produce no fuel for use outside the GPA), regardless of whether they are located within or outside of the area, have refinery/importer standards that are equal to the least of 1) 150 ppm, 2) the refinery’s or importer’s 1997–98 average sulfur level plus 30 ppm or 3) the refinery’s or importer’s lowest actual annual sulfur level plus 30 ppm in any year 2000–2003 if credits are generated. Because the refiners produce all of their fuel for use in the GPA, they are exempt from the corporate average standards in
Table IV.C–1.

Furthermore, any refiner/importer which certifies 50 percent or more of its gasoline production volume for sale as GPA gasoline in 2004 and 2005 is not required to meet the corporate pool average for that year for its entire gasoline pool. Not only would it be difficult to comply on average (if it were assumed that the GPA gasoline was 150 ppm and non-GPA gasoline was 30 ppm), but also it would undermine the achievement of the basic goal of a more orderly and efficient phase-in of low sulfur gasoline since the flexibility afforded by the GPA could be
diminished.

Otherwise, those who produce less than 50 percent of their gasoline for the GPA (which is the majority of those
refiners which market in both locations), must meet the corporate pool average standards in 2004 and 2005 for their entire gasoline pool. Thus, such refiners must compensate for the higher sulfur levels of their GPA gasoline by producing non-GPA gasoline that averages sufficiently less than 120 ppm in 2004 and 90 ppm in 2005 to ensure that their corporate average meets the corporate pool average standard for each year. Importers who provide less than 50 percent of their gasoline to the GPA must also include their GPA gasoline in their overall corporate pool average calculation. Alternatively, the refiner
can use sulfur allotments to meet the corporate pool average standard for its total gasoline production, including gasoline sold inside and outside the phase-in area. Since most refiners which sell gasoline both in and outside the GPA sell the vast majority outside the GPA the additional flexibility provided for gasoline sold in the phase-in area should not significantly affect compliance with the corporate pool average standard for a refiner’s nationwide production.

vi. How Do Refiners/Importers Apply for the Geographic Phase-in Area
Standards?

As part of program administration, we are requiring that any refiner/importer


### 6759 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

84 If a refinery has a baseline sulfur level higher than 120 ppm (as described below in IV.C.1.c.v.), then credits are generated from the baseline to 120 ppm and allotments from 120 ppm to the new sulfur level (and discounted 20 percent if applicable). expecting to sell gasoline in this area during the phase-in period (2004–2006) make application to EPA in writing by December 31, 2000. This application would provide the minimum information needed by EPA to characterize a refiner’s/importer’s participation, establish the applicable standards if the 1997–98 average is less than 150 ppm, and establish our enforcement program for refiners/ importers in this area for gasoline entering or leaving the area. Participation on the part of any refinery or importer is voluntary. At any time, a refiner/importer who previously opted into the GPA program may produce gasoline meeting the standards in Table IV.C–1 in the GPA, or may cease producing gasoline for the GPA (and produce gasoline meeting the standards in Table IV.C–1 solely outside of the GPA). Such a decision would affect the averages/caps which apply to the gasoline sold in the GPA. Gasoline sold in the GPA that is not designated as GPA gasoline is considered Non-GPA gasoline for purposes of compliance with the corporate pool average requirement and refinery average requirements.

vii. How Will EPA Establish the GPA in Adjacent States?

EPA is establishing a geographic phase-in area that encompasses eight states (MT, ND, ID WY, CO, UT, NM, AK). In addition, counties and tribal lands in states immediately adjacent to these which received a majority of their gasoline in calendar year 1999 from a refinery(ies) located within the GPA will be covered by the phase-in area provisions. The criteria to identify these
additional counties and tribal areas are designed to identify areas whose gasoline distribution system is closely tied to the eight states such that they
share the same characteristics of gasoline supply. Therefore, dispensing outlets (retail and private) in such areas
will continue to have access to that gasoline in most cases. Distribution and production of gasoline in these additional areas will be subject to the same standards and requirements as gasoline in the eight states identified
above.

At this time, EPA is not able to identify all the counties and tribal lands that would be included in the phase in area. In light of the air quality benefits of introducing low sulfur gasoline as quickly as possible, we want to ensure that the phase-in area is accurately identified and that including any areas outside these eight states will not have a significant adverse air quality impact on any counties or tribal lands that are included in the phase-in area. EPA will be working with interested stakeholders
will to conduct an assessment to
determine which counties/tribal lands within the immediately adjacent states
meet the criteria as described in the regulatory text. EPA expects to complete action on this assessment by December 31, 2000. c. How Does the Sulfur Averaging, Banking, and Trading Program Work?

The sulfur ABT program provides flexibility to refiners by giving them more time to bring all of their refineries into compliance with the corporate averages in 2004 and 2005 as well as the 30 ppm individual refinery standard in 2005 and beyond. ABT will provide the opportunity for reduced costs by allowing the industry the flexibility to average sulfur levels among different refineries, between companies, and across time. With ABT, some refineries will be able to delay installation of desulfurization equipment, because other refineries will generate sulfur allotments and credits through early sulfur reductions. In this way,
installation of desulfurization technology will be spread out over a longer period of time than would be the case without ABT. Since, with the banking provisions, reductions in annual average sulfur levels which occur as early as 2000 have a value during program implementation, the ABT program provides an incentive for technological innovation and the early implementation of refining technology.

The ABT program also provides the opportunity for meaningful emissions
reductions in 2004 because it allows the Tier 2 standards to be implemented earlier than might otherwise have been possible (if the Tier 2 standards were delayed to provide the refining industry more time to comply), and because it provides direct environmental benefits even in the years before Tier 2 vehicles
are introduced. One benefit is related to the effect of gasoline sulfur on exhaust emissions, as discussed in the Regulatory Impact Analysis. This
benefit will result both from older vehicles on the road (Tier 0 and Tier 1 emission control technologies, which have some degree of sulfur sensitivity
and will benefit from sulfur reductions which occur prior to implementation of the refiner and refinery standards summarized in Table IV.C–1) and from NLEV vehicles (which are more
sensitive to sulfur than earlier technologies) which will continue to besold while Tier 2 vehicles are phasedin. Another environmental benefit is the reduction in atmospheric sulfur loads as a direct result of reduced gasoline sulfur levels, leading to reduced emissions of sulfur-containing compounds from
motor vehicles.

The following sections explain the requirements for participation in the sulfur ABT program for allotments and
credits.

Sulfur Allotment Program

i. Generating Allotments Prior to 2004

To provide additional incentive for early sulfur reductions and to enhance the overall feasibility and cost effectiveness of the gasoline sulfur control program, we are implementing a sulfur allotment program. While few commenters supported the sulfur allotment concept in the NPRM, a number suggested that greater flexibility for compliance in the early years would be helpful. The program described below is in addition to the early sulfur credit program described elsewhere.

For 2003, refineries can generate sulfur allotments (in ppm-gallons) by producing gasoline containing less than 60 ppm sulfur on an annual-average basis. This 60 ppm ‘‘trigger’’ was chosen
to reward refineries who demonstrate compliance using technology designed to meet the 30 ppm standard before 2005. Once this 60 ppm trigger is reached, allotments will be calculated
based on the amount of reduction from 120 ppm. 84 However, these allotments may be discounted depending on the actual sulfur level. If a refinery fully demonstrates compliance by producing gasoline with an annual average sulfur level of 0 to 30 ppm, the allotments retain their full value—they are not
discounted at all. For actual sulfur levels of 31–60 ppm, which are indicative of a partial demonstration of compliance with the ultimate low sulfur standard, the allotments are discounted 20 percent. For example, consider a refinery that has an average sulfur level of 50 ppm at the end of 2003. That refinery would have generated 56 sulfur allotments [(120 ppm ¥ 50 ppm) × 0.8

× Volume (in gallons)] to be used or sold in 2004. If that same refinery instead produced fuel with an average sulfur level of 20 ppm at the end of 2003, then it would have generated 100 sulfur allotments [(120 ppm ¥ 20 ppm) × volume (in gallons)] to be used or sold

in 2004.

ii. Generating Allotments in 2004 and

2005

For 2004 and 2005, refiners or importers (but not individual refineries)


### 6760 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

85 Allotments used for GPA gasoline compliance may be retained until February 2007. Allotments used for small refiner gasoline compliance may be retained until February 2008. can generate allotments by producing gasoline that has a sulfur level below the annual corporate average standard (120 ppm and 90 ppm). The number of allotments generated is equal to the difference between 120 ppm (or 90 ppm) and the corporate average sulfur level. Allotments generated by refiners or importers in 2004 and 2005 are not discounted, unlike some of those that are generated by refineries in 2003. Refiners that sell fuel to the GPA may also generate allotments by producing fuel that is cleaner than the corporate average standards, regardless of the volume of fuel that is produced for use in the GPA. On the other hand, as explained in Section IV.C.2., gasoline produced by small refiners who are complying with the standards in Table IV.C.–3 cannot be used to generate sulfur allotments since these producers are not required to meet a corporate average standard.

iii. Using Allotments in 2004 and 2005

Refiners and importers can use sulfur allotments that they generate or purchase from other refiners/importers to demonstrate compliance with the 120 ppm corporate standard in 2004 and the 90 ppm corporate standard in 2005.
Each refiner’s sulfur allotment for 2004
and 2005 will be calculated based on the total volume of gasoline imported and produced at their refineries (or only imported gasoline in the case of companies that only import gasoline) and the corporate pool average standard for that year. In anticipation of exceeding or falling short of the standard for any one year, companies may trade sulfur allotments, either in the compliance year or earlier (as early as the year 2000). For example, a refiner that expects to produce a total of 2.5 billion gallons of gasoline in 2004 hasa sulfur allotment of 300 billion ppmgallons (120 ppm × 2.5 billion gallons). If its corporate pool average is actually 200 ppm in 2004, it will exceed its 2004 allotment by 200 billion ppm-gallons (since 200 ppm × 2.5 billion gallons = 500 ppm-gallons), and must obtain
sulfur allotments from another refiner to offset this increase. Similarly, if this refiner expects to average 80 ppm in 2004, it has an excess of 100 billion ppm-gallons to trade to other refiners. However, if a refiner trades away part of its allotment, the refiner must still comply with the corporate standard, just
as another refiner has to do if it does not
trade allotments.

In 2005, refiners must comply both with the corporate average standard and the refinery average standard for each of
their refineries. Once a refiner has established compliance with the 90 ppm corporate average standard (with or without the use of allotments), each of

its refineries can then establish compliance with the 30 ppm refinery standard through actual production of 30 ppm gasoline or through the use of

excess allotments and/or sulfur credits. Once compliance with the 90 ppm corporate pool average standard is established, the refiner would use 90 ppm as each of its refineries actual sulfur level, then apply an appropriate

number of credits or allotments to meet the 30 ppm refinery average standard for each refinery. (See discussion below for an explanation of how a refiner can use

both sulfur ABT credits and allotments to comply with the refinery average standard in 2005.)

iv. How Long Do Allotments Last?

We expect most refiners will trade

sulfur allotments well before the end of each compliance year so they will have the needed certainty of compliance with the corporate average standard. Our program allows such trades to occur at any time during the year, although the refiner is liable for any shortfall in compliance resulting from having traded away too many allotments. A refiner may also carry over excess 2004 allotments (those generated in 2003 or 2004) for compliance with the 90 ppm corporate standard for 2005. However, those allotments must be discounted by 50 percent. This 50 percent discount factor is needed to equalize the emission impact of sulfur control between 2004 and 2005. In 2005, there is an extra model year of NLEV/Tier 2 vehicles relative to 2004. In addition, the NLEV/ Tier 2 fleet is one year older in 2005 than 2004. This increased age translates into higher vehicle emissions due to general deterioration. Since sulfur acts on a percentage basis, the absolute emission increase due to sulfur impacts on vehicle emission control systems in 2005 is higher than in 2004.

As discussed below in section IV.C.1.c.x, a refiner or importer may

convert allotments into credits in 2004 and 2005 for compliance with the refinery average standards in 2005 and beyond. All transactions between refiners involving sulfur allotments must conclude by the last day of February in the calendar year following the compliance year in which the

allotments are to be used. 85 Sulfur Credit Program

v. Establishing Individual Refinery Sulfur Baselines for Credit Generation Purposes

The purpose of establishing a sulfur baseline for each refinery is to provide a starting point for determining sulfur credits for reductions in gasoline sulfur levels. We proposed that refiners would
have to establish a sulfur baseline for each individual refinery, by submitting to us data establishing their annual average gasoline sulfur level based on the average of their 1997 and 1998 operations. We would review the data and, barring any discrepancies, approve a sulfur baseline for each refinery. We received comments supporting this option as well as comments stating that the time involved for this application and approval process would delay the refiner’s ability to plan for and begin construction of gasoline desulfurization technology. Refiners would want the certainty of an approved sulfur baseline before making investment decisions,
and thus would wait to obtain EPA’s approval before proceeding. We also received comments about what year(s) would be most appropriate to use to
establish a sulfur baseline. Some of these comments argued for the use of existing, approved 1990 baselines, or some adjusted version of 1990 baselines, rather than new data, to expedite the process of establishing sulfur baselines.

We also proposed a different sulfur baseline for reformulated gasoline (RFG) produced in the summer for those refineries which produce reformulated gasoline. While the conventional gasoline sulfur baseline (and the baseline for winter RFG) was proposed to be tied to current sulfur levels, the
baseline for summer reformulated gasoline was proposed to be 150 ppm, the approximate level we expect summer reformulated gasoline to contain in 2000 and beyond because of the Phase II reformulated gasoline requirements, which take effect in 2000. We argued that winter RFG did not have any de facto sulfur restrictions, and thus
winter RFG should be counted with conventional gasoline for the purpose of credit generation relative to the refinery’s conventional gasoline sulfur
baseline.

Since the proposal, we have learned that overall gasoline sulfur levels (conventional plus reformulated) are significantly lower than they were in 1990. As explained in the Regulatory Impact Analysis, national average sulfur
levels when both conventional and reformulated gasolines are considered dropped to 306 ppm in 1997 and 268 ppm in 1998, compared to the 1990


### 6761 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

86 Refiners may, however, include oxygen added downstream of the refinery when determining

Continued national gasoline sulfur average of 339 ppm, decreases of 10 and 21 percent, respectively. The substantial drop
between 1997 and 1998 seems to be related to the mandatory use of the Complex Model, which began in 1998 and had implications for both reformulated and conventional gasoline compliance. Thus, we have become convinced that the most appropriate
sulfur baseline would be based on data which establish current sulfur levels, not on data which are nearly ten years old. We considered reducing all 1990 baselines by 21 percent to reflect the national average decrease since 1990, but determined that this approach would be inappropriate because some
refiners have reduced levels substantially more than 10–21 percent since 1990, and would thus be eligible to generate a very large number of credits for reductions that have already
been made.

Furthermore, as we proposed, and some commenters argued, we have concluded that averaging data from two years is the most appropriate approach, because averaging over two years will help to account for any unusual variations in operations that may have
occurred at individual refineries in either of these years. We concluded that averaging data from 1998 and 1999 is not feasible, because the 1999 data will not be fully available to EPA until after the reporting deadline of May 2000. Hence, we believe it is preferable to use 1997 and 1998 data, rather than delaying the time baselines are established. We do not expect significant changes in 1999 sulfur levels relative to 1998 levels, so we believe the use of the 1997–1998 data provides a reasonable representation of current
sulfur levels.

We have also learned that summer reformulated gasoline is already averaging close to our expected sulfur level for the year 2000. Winter RFG does not show this same decrease, presumably because refiners are shifting high sulfur blendstocks out of RFG in
the summer but back into RFG in the winter to maintain compliance with the conventional gasoline antidumping requirements. Thus, it appears that if we held summer RFG to a lower baseline, as proposed, we would have to raise the winter RFG baseline commensurately to reflect actual refinery operations. The net environmental impact would be no different than if we had a single sulfur baseline applying to all RFG, or to all gasoline produced at the refinery, since the annual pool sulfur levels are constant even while there may be seasonal variations. Therefore, we are not finalizing a separate sulfur baseline for summer RFG, but rather combined conventional and reformulated gasoline
sulfur levels.

Having considered the comments we
received and the new data available to us, we have concluded that refiner
sulfur baselines should be established from 1997 and 1998 operating data. Hence, we are requiring refiners which wish to generate sulfur credits prior to
2004 to establish a 1997–98 sulfur baseline for each refinery at which they intend to generate credits. We believe the process we have defined will minimize the burden to the industry
and the time it will take for us to review and approve the sulfur baselines. Specifically, refiners which plan to generate sulfur credits must submit to
us information which establishes the batch report numbers, sulfur levels, and volumes of each batch of gasoline produced in 1997 and 1998, as well as the annual average sulfur level
calculated from these data. Within 60 days, we will review the application and notify the refiner of approval or of any discrepancies we find in the data submitted. If we do not respond within 60 days, the baseline should be considered to be approved.

While we expect most refiners will apply for a sulfur baseline in the near future (to maximize the time that they can generate credits before 2004), there is no cut-off date for applying for a sulfur baseline. However, if the refiner wishes to generate credits for a given calendar year, we must receive his baseline application no later than September 30 of that year to provide us adequate time to review the baseline prior to the end of the year (at which time any credits generated in that year would be assessed and reported by the refiner). We believe that this approach for establishing sulfur baselines meets our goal of providing a workable ABT program that refiners can take advantage beginning in the year 2000, without sacrificing the environmental benefits of
the sulfur standards.

Foreign refiners which have already established an individual refinery baseline with us, and thus have submitted reports on all batches of gasoline sent to the U.S. in 1997 and 1998, may follow this same procedure if they wish to generate sulfur credits prior to 2004. Foreign refiners which have not reported 1997–98 gasoline qualities to us must follow an alternate approach. Specifically, they must follow the general requirements of our protocol for establishing individual refinery baselines (see §§ 80.91–94 and also § 80.410) by providing sufficient data to establish the volume of gasoline imported to the U.S. from each refinery in 1997–98 and the annual average sulfur level of that gasoline. If the test method used to identify the sulfur level differs from the one specified in today’s action, the refiner must provide
sufficient information about the test
method to allow us to evaluate the appropriateness of the alternative.
Because this information will be new to us, we may require more time to review and approve their 1997–98 sulfur baseline. But, consistent with our previous handling of foreign refiner submissions, once we have determined that the submission is complete and the protocol has been followed, they may use the baseline while waiting for our formal approval. However, the refiner
will be held to the baseline that is ultimately approved. A foreign refiner who is unable to generate adequate data
to establish a 1997–98 sulfur baseline will not be permitted to generate sulfur
credits in 2000–2003.

Small refiners that plan to request small refiner standards (as provided in Section IV.C.2 below) which also want to generate early sulfur ABT credits will use the same data required to define
their small refiner baseline to determine their baseline for the ABT program. In other words, if a refiner becomes a small
refiner under our definition and procedures, credits generated by that refinery would be calculated relative to the refinery’s actual 1997–98 sulfur average. The trigger for generating sulfur credits under the ABT program (discussed in the next section) would still apply for small refiners generating credits prior to 2004 relative to their 1997–98 sulfur average. In addition, the applicable interim sulfur standard for small refiners who generate credits through sulfur reductions prior to 2004
will be calculated based on the reduced sulfur level, rather than the 1997–98 baseline level, as explained below in

Section IV.C.2.

Importers and gasoline blenders will not be assigned a sulfur baseline because they are not eligible to generate early credits (prior to 2004) under the ABT program. This includes gasoline refiners who are also importers; such parties cannot generate sulfur credits prior to 2004 on the basis of their imported gasoline but may only generate credits based on the gasoline produced by their refinery(ies). It also includes oxygenate blenders, who, as discussed in Section VI below, are not subject to the sulfur standards but are responsible for compliance with the downstream provisions. 86 For importers


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compliance with the sulfur standards and the provisions of the ABT program. This is consistent with existing provisions for reformulated and conventional gasolines.

87 As explained in Section IV.C.1.c.ix, credits generated before 2004 expire in 2006, except for small refiners and credits used for GPA gasoline compliance. and most gasoline blenders, this represents a change from our proposal, but one we believe is appropriate and necessary to ensure that the
environmental benefits of the ABT program are maintained. The ABT program allows the refining industry to trade off early sulfur reductions (2000– 2003) for slight delays in complying with the 30 ppm refinery average
standard in 2005–2006. 87 We have designed the ABT program to ensure that sufficient credits can be generated by refiners (domestic or foreign) to
enable a smooth transition to the 30 ppm standard. Importers and blenders
do not have the same need for the ABT program that refiners have because they
will not have to make the same level of
investment in desulfurization technology and thus do not need credits generated before 2004 to help their transition to the 30 ppm average standard after 2004. Furthermore, credits could be generated by importers without the overall pool of imported gasoline becoming incrementally cleaner. For example, say that Importer
A had a 1997/98 sulfur baseline of 600 ppm and Importer B had a sulfur baseline of 100 ppm. In 2002, Importer B could transfer/sell its 100 ppm gasoline to Importer A prior to unloading the fuel at the port of entry. Once the import transaction was completed, Importer A will have generated 500 ppm (multiplied by the fuel volume) credits without any fuel becoming incrementally cleaner. We are concerned that if importers and blenders were allowed to generate early credits, they would generate far more
credits than needed to make the ABT program work, without necessarily achieving early environmental benefits—credits which either importers or refiners would be able to use to delay compliance with the 30 ppm standard in 2005 and beyond. This would delay
the environmental benefits of our program by prolonging the industry’s transition to the 30 ppm standard.

In the proposal, we also discussed the need for a baseline gasoline volume as
well as a baseline sulfur level. This stemmed from the design of our current conventional gasoline anti-dumping program, which requires a baseline
volume so that we can confirm that conventional gasoline is no dirtier now than it was in 1990. However, for the gasoline sulfur ABT program, we have
determined that there is no need to
restrict refineries’ sulfur baselines (against which they can generate sulfur credits) to a specific volume of gasoline. The purpose of the ABT program is to encourage early sulfur reductions by some refineries, and we see no need to
limit the amount of credits such a refinery can generate on the basis of a historic volume of gasoline production. In fact, additional volumes of cleaner gasoline should achieve additional early
environmental benefits.

vi. Generating Sulfur Credits Prior to

2004

In our proposal, we discussed a credit generation trigger of 150 ppm for early credit generation (2000–2003), arguing that we wanted to encourage investment in desulfurization technologies that refineries ultimately need to get to a 30 ppm average. Many comments we received argued that the 150 ppm trigger was too restrictive, requiring capital
investments that most refiners could not make earlier than 2004 (due to construction limitations, among other reasons). Thus, few credits would be generated, and without sufficient certainty that credits would be generated, refiners would not be able to count on the flexibility that the ABT program was intended to provide when planning their compliance strategies for 2004 and beyond.

Having considered these comments and reanalyzed the ability of the industry to comply with the standards in 2004 (as we discussed above at the introduction to section IV.C.1), we have concluded that the proposed 150 ppm trigger would inappropriately limit the
credits available. While we want to encourage refiners to make reductions early, we do not want to preclude refiners from making less capital
intensive sulfur reductions in the short term while they prepare to reach the 30 ppm average in the long term. At the same time, we believe that a refinery should be required to demonstrate that
the sulfur reduction was real and not just a consequence of national variations from year to year. Hence, we are establishing a trigger which we believe represents a sulfur reduction that requires action above and beyond simple annual or even seasonal
fluctuations in crude oil sulfur level or product slate variations that could have a very small impact on annual sulfur

average.

During the period 2000–2003, credits can be generated annually by any refinery that produces gasoline averaging at least 10 percent lower than that refinery’s baseline sulfur level. In other words, to generate credits, the refinery’s annual average sulfur level for all of its gasoline on average must be 0.9

× (baseline sulfur level). Once this ‘‘trigger’’ is reached, credits will be
calculated based on the amount of reduction from the refinery’s sulfur baseline. For example, if in 2002 a refinery reduced its annual average sulfur level from a baseline of 450 ppm to 150 ppm (well below the trigger of

0.9×450=405 ppm), its sulfur credits
will be determined based on the difference in annual sulfur level (450– 150=300 ppm) multiplied by the volume of gasoline produced in 2002. Similarly, foreign refineries with an individual sulfur baseline can generate credits in these years as long as the annual average sulfur level of the gasoline imported to the U.S. from that refinery is lower than 90 percent of the baseline sulfur level.

Although by adopting a more modest trigger for credit generation we are enabling more credits to be generated,
the environment will still benefit from our program. Although the use of a more modest trigger keyed to each refinery’s sulfur baseline may allow more credits to be generated, we believe this will only occur because the credit program is providing incentives to refineries to reduce sulfur levels earlier than they would have otherwise, particularly with a strict 150 ppm trigger. Thus, more lower sulfur gasoline will be in the marketplace prior to 2004 than would otherwise have occurred, given our understanding of the state of desulfurization technologies and the likely pattern of investments by the industry. With our corporate average and cap standards, sulfur levels will continue to decrease after 2004, even if individual refineries take an added year or two to meet the 30 ppm standard.

We had also proposed that credit generation prior to 2004 would be different for reformulated gasoline than for conventional gasoline, because reformulated gasoline’s assigned sulfur baseline was proposed to be 150 ppm. Thus, we proposed that credits could only be generated from reformulated gasoline if the sulfur level averaged below 150 ppm, and that the credits
would be calculated based on the difference between 150 ppm and the new, lower average. Since we have not finalized a separate baseline for reformulated gasolines, we are not adopting a different process for generating credits from reformulated gasoline. All gasoline produced at the refinery in 2000 (and beyond) is considered in calculating the annual average sulfur level, compliance with the 90 percent trigger, and the sulfur credits earned, if any.


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88 Excluding California. Several states have adopted or are considering adopting gasoline sulfur control programs (see discussion at
section IV.C.1.d below on state sulfur programs). While we had proposed to exclude this gasoline from sulfur credit generation, we have reconsidered our position. Gasoline produced in response

to state 88 requirements can be included in the refinery’s calculation of sulfur credits generated in a given year. However, this gasoline will be included in the total volume of gasoline produced by that refinery, requiring the annual average sulfur level for total gasoline produced at that refinery to exceed the trigger specified above to generate any
credits at all.

vii. Generating Sulfur Credits in 2004 and Beyond

In 2004 and beyond, refineries, blenders, and importers can generate credits, but only if the actual annual sulfur level of all gasoline produced or imported averages below 30 ppm, and only for the difference between the
standard and the actual annual sulfur average. (For example, a refinery producing gasoline in 2005 that averages 25 ppm can generate 30–25=5 ppm sulfur credits on the total volume of gasoline produced at that refinery.) However, since in 2004 and beyond importers are the regulated party responsible for ensuring that imported gasoline meets the sulfur standards, foreign gasoline would in effect generate sulfur credits through the importer beginning in 2004. Foreign refineries which want to send gasoline containing less than 30 ppm sulfur to the U.S. would still benefit from doing so by making appropriate arrangements with importers, which are subject to all of our
standards.

viii. Using Sulfur Credits

Refineries, blenders, and importers
can use sulfur credits to demonstrate compliance with the 30 ppm annual average refinery standard in 2005 and beyond, if they are unable to meet the standard with actual gasoline production. During 2005 and 2006 only, refineries may use credits banked by that refinery in 2000–2003 as a result of early sulfur reductions, or credits purchased from other refineries which have banked early sulfur credits. Blenders and importers can purchase credits from refiners (including any foreign refiners which generated early credits), or use credits they generated in 2004 and beyond. All transactions will have to be concluded by the last day of February after the close of the annual compliance period (2005, 2006, etc.).

As discussed above, 2005 is the only year when averaging and trading against the corporate average and averaging, banking, and trading against the refinery average are both allowed. In that year, sulfur credits may only be used against the 30 ppm standard for each refinery
once the refiner has demonstrated compliance with the corporate pool average standard. The refiner must meet his corporate average based on actual sulfur levels or through a trade for
sulfur allotments if it falls short of the 90 ppm corporate average standard. At that point, each of his refineries is evaluated for compliance with the 30 ppm refinery average standard. Those refineries that are not producing gasoline averaging 30 ppm sulfur must obtain sulfur credits generated in 2005
or earlier and/or sulfur allotments to bring the refinery’s sulfur average from the actual level (a maximum of 90 ppm for each refinery, since by meeting the corporate average, even if in part through the use of allotments, each refinery in the company will be considered to average no more than 90 ppm) down to 30 ppm.

Refineries or importers which sell some or all of their gasoline in the GPA (and which have elected to participate in the phase-in) may also use sulfur credits to meet their refinery averages in 2004–2006. However, because this gasoline must be designated for sale in the GPA, they must account separately for compliance with the 150 ppm refinery average for gasoline sold in the phase-in area and with the 30 ppm refinery average for gasoline sold outside of that area. Thus, in 2004, such refiners/importers may use sulfur credits to establish compliance with the 150 ppm standard for gasoline sold in the phase-in area, if required. In 2005 and 2006, they may use credits to meet the 150 ppm standard for gasoline sold
in the area and/or use credits to meet the 30 ppm standard for gasoline sold
outside of the area.

As explained in section IV.C.1.b., some of the refiners participating in the GPA are exempt from the corporate average standards, but may use either
sulfur credits or sulfur allotments in 2004–2006 to establish compliance with the 150 ppm refinery average standard. Those that are not exempt from the corporate average standards may use sulfur allotments only to meet the corporate average standards. For such refiners, compliance with the corporate average standard will be measured first (using allotments if needed), then compliance with the refinery average standard (using credits and/or allotments as needed) in the same
manner as described above for refiners who sell all of their gasoline outside of
the GPA.

Foreign refineries are not required to comply with the 30 ppm refinery standard in 2005 and beyond; instead, compliance for foreign gasoline is required by the importer. Sulfur credits generated by foreign refineries prior to 2004 will still have value, since these
refineries can sell sulfur credits to U.S. refineries, blenders, or importers who
need credits to meet the standard in 2005 or beyond. In fact, foreign refiner’s credits could simply be transferred to the importer which is importing that refinery’s gasoline into the U.S. For example, a foreign refiner could send gasoline exceeding 30 ppm on average to an importer and transfer the appropriate amount of sulfur credits it generated prior to 2004 to allow the importer to meet the 30 ppm standard. Similarly, after 2004 a foreign refiner may send gasoline containing less than 30 ppm to the U.S. through an importer, and the importer would benefit from generating credits (and presumably
would include the value of these credits
in the financial transaction with the foreign refinery).

As explained in Section IV.C.3.b. above, in 2005 no batch of domestically produced or imported gasoline can exceed 300 ppm, and a refiner’s/ importer’s annual corporate pool average sulfur level cannot exceed 90 ppm, except for gasoline sold in the GPA or by small refiners complying
with the standards in Table IV.C.–3. In 2006 and beyond, sulfur is capped at 80 ppm and there is no longer a corporate pool average standard. These standards (as well as the 300 ppm cap and corporate pool averages) cannot be met through the use of credits generated under the ABT program. As described above, credits may only be applied to demonstrate compliance with the 30 ppm refinery standard, not to the corporate pool average or the cap. Given the limitations that the 80 ppm cap places on sulfur levels in 2006 and beyond, we do not expect many sulfur credits to be used in future years of this program (since, even with the use of credits, no gasoline may exceed 80 ppm in these years).

We allow an individual refinery that does not meet the 30 ppm standard in a particular year to carry forward the credit debt one year. Under this provision, the refinery will have to make up the credit deficit and come into compliance with the 30 ppm standard the next calendar year, or face penalties. This provision will in no way absolve the refiner from having to meet the


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applicable per-gallon cap standard or, when applicable, the corporate average standard. This provision will provide
some relief for refiners faced with an unexpected shutdown or that otherwise
were unable to obtain sufficient credits to meet the 30 ppm standard. This provision is only available through 2010. After that time, we expect many refineries to be able to consistently operate below 30 ppm, generating a pool
of credits which other refineries could purchase in the event of an unforeseen upset. However, in no circumstances after 2005 can the refinery producegasoline exceeding the 80 ppm pergallon cap standard (with the exception of small refiners, as discussed in Section IV.C.2 below). The carry-forward provision does not apply to compliance with the 150 ppm refinery average standard applicable in the GPA.

We have some concern that the potential exists for credits to be generated by one party and subsequently purchased or used in good faith by another, and later found to have been calculated or created improperly or
otherwise determined to be invalid. For this reason, we proposed that both the seller and purchaser would have to adjust their sulfur calculations to reflect the proper credits and either party (or both) could be deemed in violation of the standards and other requirements if the adjusted calculations demonstrate noncompliance with an applicable standard. One commenter, representing a number of refiners, objected to this approach.

Nevertheless, our strong preference is
to hold the credit or allotment seller liable for the violation, as opposed to the credit or allotment purchaser. As a general matter we would expect to enforce a shortfall in compliance calculations (caused by the good faith purchase of invalid credits) against a good faith purchaser only in cases
where we are unable to recover valid
credits from the seller to cover the compliance shortfall. Moreover, in
settlement of such cases we would strongly encourage the seller to purchase credits to cover the good faith purchaser’s credit shortfall. Under the deficit provisions of section 80.205(e), for compliance periods through 2010, a credit shortfall may be corrected if the
conditions of that section are met. EPA will consider covering a credit deficit through the purchase of valid credits a very important factor in mitigation of any case against a good faith purchaser, whether the purchase of valid credits is made by the seller or by the purchaser.

Some commenters stated that sulfur credits should be transferred directly from the refiner or importer that generated them to the party that will use them, as we had proposed. We believe that this helps to ensure that parties purchasing credits will be better able to
assess the likelihood that the credits will be valid, and aids compliance monitoring. Therefore, the final rule adopts this provision, with the exception that where a credit generator transfers credits to a refiner or importer who cannot use all the credits, that transferee may transfer the credits to another refiner or importer. That second transferee cannot again transfer the credits; they must either be used or terminated by the second transferee. Nevertheless, there is nothing in the final rule that would prevent a person who is not a refiner or importer from facilitating the transfer of credits from parties that have generated them to parties who need them for compliance,

e.g., a broker who would act like a real estate broker. Therefore, under today’s rule, any person may act as a credit or allotment broker, whether or not such person is a refiner or importer, so long
as the title to the credits or allotments are transferred directly from the generator to the user. Furthermore, any party ( e.g., refiner, importer, or blender) who can generate and hold credits may
also resell them.

ix. How Long Do Credits Last?

The ABT program is designed to encourage sulfur reductions earlier than the standards require, by providing a market for credit generation. The emissions benefits of these early
reductions are most valuable in the early years of the ABT program when national average levels remain substantially higher than the final 30 ppm average standard. At the same time, these emissions reductions are offset in time by higher emissions incurred by later vehicles which use gasoline with a higher sulfur level.
Because the overall intention of the gasoline sulfur program is to enable and protect Tier 2 vehicles and provide time
for refiners to select and construct desulfurization equipment, sulfur
credits should have a limited life to limit the degree to which later Tier 2 vehicles are exposed to higher sulfur
levels.

The ABT program is also designed to ease implementation of the new standards, particularly the refinery average standard, and the credits will be of their greatest value to refineries during the first few years of the program. ABT is not intended to permit a refinery to operate substantially above the standard for a protracted time period. While limiting credit life may reduce the incentive to generate credits for some refineries, the credit program will be of relatively small value to any refinery/importer that held credits for a protracted period of time and did not need to use them. This is particularly true in 2006 and beyond, when the 80 ppm cap limits the need for and value of any credits the refinery may possess.

Hence, we are finalizing limitations
on the life of credits which differ somewhat from our proposal. Credits generated prior to 2004 must be used for compliance purposes and calculations with respect to gasoline produced on or before December 31, 2006. These credits can be used to meet the 30 ppm
standard in 2005 or 2006. This expiration date applies to credits used by the refinery which generated the credits, as well as credits transferred to another refinery. While the proposal presented a life through 2007 for credits generated early, we have shortened this life span one year to reflect the fact that early credits are intended to enable and ease compliance with the 30 ppm standard in the first years of the program, allowing refiners to spread out investments without compromising the environmental benefits of the program. At the beginning of 2006, all gasoline (except that produced by small refiners and that marketed in the GPA) will be capped at 80 ppm, and by the end of 2006, every refinery should be capable of producing gasoline that meets the 30 ppm standard. Hence, the value of the early credits diminishes greatly. It should be noted that early credits can be used for GPA certified gasoline through 2006 and for small refiner gasoline through 2007.

Credits generated in 2004 and beyond will have to be used within five years of the year in which they were generated. If these credits are traded to another party during that five year period, they will have to be used by the new owner within that same five years, regardless of when the transfer occurs. This is a change from our proposal, which provided for a potential maximum ten-year life for credits that were generated and then traded in the fifth year to another party. However, we believe this approach is more consistent with our environmental goals of keeping sulfur levels averaging 30 ppm in 2006 and beyond. With the 80 ppm cap, refiners will be able to use only very few credits if they are unable to meet the 30 ppm average in 2006 or beyond. Therefore, limiting credit life to five years will likely have minimal impact on the actual use of credits. A longer credit life will make tracking and enforcement difficult, and could have negative environmental consequences. Hence, we have limited credit life to


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89 The term ‘‘state’’ or ‘‘states’’ includes political
subdivisions thereof.

90 In evaluating whether a state fuel prohibition or control is ‘‘identical’’ to a prohibition or control adopted by EPA, EPA might consider but is not limited to the following factors in comparing the measures: (1) The level of an emission reduction or pollution control standard; (2) the use of ‘‘per gallon’’ or ‘‘averaged’’ amounts in setting that level; (3) the effect on that level (if averaged) of the use of different averaging pools; (4) the lead time allowed to the affected industry for compliance; and (5) the test method(s) and sampling requirements used in determining compliance.

91 In addition, EPA notes that there are existing

federal NO X performance standards which apply to RFG and conventional gasoline and that state controls respecting NO X performance are also preempted under 211(c)(4)(A). five years. Consistent with our other recordkeeping and reporting requirements, the five-year expiration date will be assessed as of the last day of February after the five year deadline. Hence, for example, credits generated in 2005 will expire as of the last day of February, 2011. Again, no third-party
transfers are allowed.

x. Conversion of Allotments Into Credits

A refiner or importer may convert allotments into credits for compliance with the refinery average standards in 2005 and beyond. Allotments that are generated by reducing gasoline sulfur levels to 30 ppm or higher (defined as Type ‘‘A’’ allotments) are equivalent to credits generated in 2000–2003. These allotments may be (1) used as allotments by a refiner for compliance with the corporate average standard in 2004 and 2005 or (2) converted into credits to be used by the refiner’s refineries for compliance with the refinery average
standard in 2005 and 2006.

Allotments that are generated by reducing gasoline sulfur levels to lower than 30 ppm (defined as Type ‘‘B’’ allotments) are equivalent to credits generated in 2004 and beyond (by producing gasoline with less than 30 ppm sulfur). Similar to Type ‘‘A’’ allotments, these allotments may be (1) used as allotments by a refiner for compliance with the corporate average standard in 2004 and 2005 or (2) converted into credits to be used by the refiner’s refineries for compliance with the refinery average standard in 2005 and beyond.

Allotments or credits that are used by refiners for compliance with the GPA gasoline standards must be used by the last day of February 2007. Allotments or credits used by small refiners for compliance with the small refiner standards must be used by the last day of February 2008. Any allotments, whether Type ‘‘A’’ or ‘‘B’’, that are carried over for compliance with the corporate and refinery average standards for 2005 must be discounted by 50 percent as discussed in above. Any
allotments that are converted to credits ( e.g., in 2004) and then carried over to 2005 are not discounted. However, once the conversion and carry-over has taken place (such that the allotments have become credits), the conversion cannot be reversed without applying the discount factor. That is to say, once a
2003 or 2004 allotment is converted to a credit and carried over to 2005, the credit can only be re-converted into an allotment that is discounted 50 percent. d. How Are State Sulfur Programs Affected by EPA’s Program?

Section 211(c)(4)(A) of the CAA prohibits states 89 from prescribing or attempting to enforce controls or prohibitions respecting any fuel characteristic or component if EPA has prescribed a control or prohibition applicable to such fuel characteristic or component under section 211(c)(1). This preemption applies to all states except California, as explained in section 211(c)(4)(B). For states other than California, the Act provides two mechanisms for avoiding preemption. First, section 211(c)(4)(A)(ii) creates an exception to preemption for state prohibitions or controls that are
identical 90 to the prohibition or control adopted by EPA. Second, states may seek EPA approval of SIP revisions containing fuel control measures, as described in section 211(c)(4)(C). EPA may approve such SIP revisions, and thereby ‘‘waive’’ preemption, only if it finds the state control or prohibition ‘‘is necessary to achieve the national primary or secondary ambient air quality standard which the plan implements.’’

We are adopting the sulfur standards pursuant to our authority under section 211(c)(1). Thus, we believe that today’s action results in the clear preemption of future state actions to prescribe or
enforce fuel sulfur controls. 91 States with fuel sulfur control programs not already approved into their SIPs will
therefore need to obtain a waiver from us under the provisions described in section 211(c)(4)(C) for all state fuel sulfur control measures, unless the state
standard is identical to our sulfur
standard.

Section 211(c)(4)(A) preempts state fuel controls if EPA has ‘‘prescribed’’ federal controls. We read this language to preempt non-identical state standards on the date of promulgation of the standards, as opposed to the date the standards become enforceable. Thus, today’s action preempts state actions as of December 21, 1999, even though the standards will not require sulfur
reductions until 2004. This interpretation is consistent with EPA actions applying other federal fuel

measures. See 54 Fed. Reg. 19173 (May 4, 1989) (noting preemption of
Massachusetts state RVP measure before start of first control period for federal RVP). We also believe this interpretation
is consistent with the intent behind section 211(c)(4)(A). Though the standards are not immediately enforceable, they will have an immediate impact on refiners’ investment decisions. We believe, by adopting 211(c)(4)(A), Congress
intended to limit state fuel controls that differ from the federal programs, for example, in the judgments as to level of the standard or its stringency. The lead time to implement a standard should be treated the same way.

Aside from the explicit preemption in Section 211(c)(4)(A), a court could also
consider whether a state sulfur control is implicitly preempted under the Supremacy Clause of the U.S.
Constitution. Courts have determined that a state law is preempted by federal law where the state requirement actually conflicts with federal law by preventing compliance with both federal and state requirements, or by standing as an obstacle to accomplishment of Congressional objectives. A court could thus consider whether a given state sulfur control is preempted, notwithstanding waiver of preemption under 211(c)(4)(C), if it places such significant cost and
investment burdens on refiners that
refiners cannot meet both state and federal requirements in time, or if the
state control would otherwise meet the criteria for conflict preemption.

2. Hardship Provision for Qualifying
Refiners

This section describes various provisions for certain qualifying refiners who may face hardship circumstances.

a. Hardship Provision for Qualifying
Small Refiners

In developing our gasoline sulfur program, we evaluated the need and the ability of refiners to meet the 30/80 standards as expeditiously as possible. This analysis is described in detail in the RIA. As a part of this analysis, we found that while the majority of refiners
would be able to meet the needed air quality goals in the 2004–2006 time frame, there would be some refiners who would face particularly difficult
circumstances which would cause them to have more difficulty, in comparison


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to the industry as a whole, in meeting
the standards.

In order to ensure that the vast majority of the program could be implemented reasonably quickly in order to achieve the air quality benefits sooner, rather than basing the time
frame on the lowest common denominator we have provided an extended phase-in for a small group of refiners that represents less than four percent of the overall gasoline volume, and a much smaller percentage in the areas of greatest environmental need. As described in more detail below, and in Chapter VIII of the RIA, we concluded that refineries owned by small businesses face unique hardship circumstances, compared to larger companies.

The primary reason for this
consideration is that small businesses lack the resources available to large companies which enable the large companies (including those large companies that own small volume refineries) to raise capital for investing in desulfurization equipment. The small businesses are also likely to have insufficient time to secure loans, compete for engineering resources, and complete construction of the needed desulfurization equipment in time to meet the standards adopted today which begin in 2004.

The emissions benefits of low sulfur gasoline are needed as soon as possible, for two primary reasons: (1) To reduce ozone and other harmful air pollutants, and (2) to enable vehicle emissions control technology for Tier 2 vehicles. Since our analysis showed that small businesses in particular face hardship circumstances, we are adopting temporary, interim standards that will provide refineries owned by small
businesses additional time to meet the ultimate 30 ppm refinery average and 80 ppm per gallon cap standards. This approach allows us to achieve the
needed emission reductions in the 2004–2007 time frame because hardship circumstances are expected to be faced by only a small portion of the refining industry.

We believe that these temporary, interim standards are an effective way to phase in the low sulfur standards as expeditiously as is feasible thereby achieving significant air quality benefits in an expeditious manner. This section describes the special provisions we are offering small businesses to mitigate the impacts of our program on them and generally explains the process we undertook to analyze those impacts.
Please refer to the RTC document for a
detailed discussion of comments received on these provisions, and to the RIA for a more detailed discussion of our analysis of small refiner

circumstances.

As explained in the regulatory flexibility analysis in Section VIII.B. of this document and in Chapter 8 of the RIA, we considered the impacts of our proposed regulations on small businesses. We have historically, as a matter of practice, considered the potential impacts of our regulations on small businesses, as discussed in more detail in Section IV.C.2.a.ii., below. The analysis of small business impacts conducted for this rulemaking was performed in conjunction with a Small Business Advocacy Review (SBAR) Panel we convened, pursuant to the Regulatory Flexibility Act as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA). We believe that the temporary, interim standards we are adopting for small refiners contributed to our development of a framework to achieve significant environmental benefits from lower sulfur gasoline in the most expeditious manner that is reasonably practicable. In the SBREFA amendments, Congress stated that ‘‘uniform Federal regulatory * * * requirements have in numerous instances imposed unnecessary and disproportionately burdensome demands including legal, accounting, and consulting costs upon small
businesses * * * with limited resources[,]’’ and directed agencies to consider the impacts of certain actions on small entities. The final report of the
Panel is available in the docket. Through the SBREFA process, the Panel provided information and recommendations regarding:

• The significant economic impact of the proposed rule on small entities;

• Any significant alternatives to the proposed rule which would ensure that the objectives of the proposal were accomplished while minimizing the economic impact of the proposed rule on small entities;

• The projected reporting, recordkeeping, and other compliance requirements of the proposed rule; and,

• Other relevant federal rules that may duplicate, overlap, or conflict with the proposed rule.

In addition to our participation in the SBREFA process, we conducted our own outreach, fact-finding, and analysis of the potential impacts of our regulations on small businesses. Many
of the small refiners with whom we and
the Panel met indicated their belief that their businesses may close due to the substantial costs, capital and other, of meeting the 30/80 standard without
additional time. Based on these discussions and our data analysis, the Panel and we agree that small refiners would likely experience a significant and disproportionate economic hardship in reaching the objectives of our gasoline sulfur reduction program. However, the Panel also noted that the undue burden imposed upon the small refiners by our sulfur requirements
could be alleviated with additional time for compliance. We agree with the Panel on both of these points.

For today’s action, we have structured a temporary, interim compliance flexibility for qualifying small refiners, both domestic and foreign, based on the factors described below. Specifically, we structured this provision to address small refiner hardship while achieving air quality benefits expeditiously and ensuring that the reductions needed in gasoline sulfur coincide with the
introduction of Tier 2 vehicles.

First, the compliance deadlines in the program, combined with flexibility for small refiners, will achieve the air quality benefits of the program quickly, while ensuring that small refiners will have adequate time to raise capital for infrastructure changes. Many, if not most, small refiners have limited, if any, additional sources of income beyond their refinery for financing the equipment necessary to produce low sulfur gasoline. Because these small refiners typically do not have the financial backing that larger and generally more integrated companies have, they need additional time to secure capital financing from their
lenders.

Second, we believe that allowing time for sulfur-reduction technologies to be proven-out by larger refiners before small refiners have to put them in place would reduce the risks incurred by
small refiners who utilize these technologies to meet the standards. The added time would likely allow for costs
of these desulfurization units to decrease, thereby limiting the economic consequences for small refiners. Small refiners are disadvantaged by the
economies of scale that exist for the larger refining companies—capital costs and per-barrel fixed operating costs are generally higher for them.

Finally, providing small refiners more time to comply would ensure that adequate engineering and construction
resources would be available. Since most large and small refiners will need to install additional processing equipment to meet the sulfur requirements, there will be a tremendous amount of competition for technology services, engineering manpower, and construction management and labor. Our analysis


### 6767 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

shows that there are limitations to the elasticity of these resources. In addition, vendors will be more likely to contract their services with the major companies first, as their projects will offer larger profits for the vendors.

Providing this flexibility to allow small refiners to deal with hardship circumstances enables us to go forward with the phase-in of the 30 ppm sulfur standard beginning in 2004. Without this flexibility, it is possible that the benefits of the 30 ppm standard would not be achieved as quickly. By providing temporary relief to those refiners that need additional time, we are able to adopt a program that reduces gasoline sulfur levels expeditiously and in a way that is feasible for the industry
as a whole.

In addition, we believe the volume of gasoline that will be eligible for the
interim standards is small. We estimate that small refiners produce approximately four percent of all gasoline used in the U.S., excluding California. In most cases, gasoline produced by refiners is mixed with substantial amounts of other gasoline prior to retail distribution (due to the nature of the gasoline distribution system). This mixing generally results in only marginal increases in overall sulfur levels. Thus, the sulfur level of gasoline actually used by Tier 2 vehicles should generally be much lower than that produced by individual small refineries under this provision.

i. How Are Small Refiners Defined?

How We Defined ‘‘Small’’ Refiner in the Proposal

In identifying the small refiners most susceptible to the economic challenge of meeting the low-sulfur requirements, we closely examined the Small Business Administration’s (SBA) definition of small refiner for the purposes of regulation. In that assessment we
concluded that the SBA definition provided a reasonable metric for identifying small refiners that would be significantly impacted by the sulfur program requirements. By adopting the SBA definition we could expeditiously provide certainty of small refiner status to refiners who applied for the temporary compliance flexibility. Specifically, we proposed a definition where any petroleum refining company having no more than 1,500 employees throughout the corporation as of January 1, 1999 could apply for the temporary compliance flexibilities. This proposed employee limit included any subsidiaries, regardless of the number of individual gasoline-producing refineries owned by the company or the number of employees at any given refinery.

While we proposed a definition based on corporate employment, in light of the
SBA definition and the SBAR Panel’s recommendations, we also sought
comment on alternative definitions of a
small refiner. Such alternatives
included definitions based on volume of crude oil processed (at a given refinery and/or corporate-wide) or volume of gasoline produced, with the understanding that any relief offered to refiners must not substantially reduce the program’s environmental benefits.

Our Revised Small Refiner Definition

Based on comments received on the proposal, we are making two changes to
our definition of a small refiner: we are (1) revising the employee number criterion; and, (2) adopting a cap on the corporate crude oil capacity for a refining company to qualify as a small business under today’s regulations.

In regard to the employee number criterion, we are modifying how the employee number is determined, based
on comments received from SBA. As mentioned above, our proposed definition applied to any petroleum refining company having no more than 1,500 employees throughout the corporation as of January 1, 1999. We selected that date to prevent companies from ‘‘gaming’’ the system. However, as SBA pointed out in its comments, the Small Business Act regulations specify that, where the number of employees is used as a size standard, as we proposed for small refiners, size determination is based on the average number of employees for all pay periods during the preceding 12 months.

Since we intended to use SBA’s size standard in our proposal, we are incorporating that definition correctly in today’s action. It is also worth mentioning that SBA shares our concerns about preventing companies from gaming the system and that it solved this problem specifically by using the average employment over 12 months. In effect, this approach helps to prevent companies from applying for and receiving small refiner status in bad faith. An example of an inappropriate application for small refiner status would be a refiner that temporarily
reduced its workforce from 1600 employees to 1495 employees immediately before January 1, 1999 and then immediately rehired those employees after that cutoff date. Furthermore, the averaging concept was designed to properly address firms with seasonal fluctuations, according to SBA.

Second, we’re amending the small refiner definition to include a corporate crude oil capacity cap. We believe such a corporate volume limitation is necessary to ensure that only truly small
businesses benefit from the relaxed
interim standards. Refineries that process large amounts of crude are likely to be better able to install desulfurization equipment to meet the
national standards in 2004. In addition to ensuring that the interim standards target the appropriate group of refiners that need additional time, the volume
limit also serves to ensure that the volume of gasoline subject to such standards is not significant. In addition, we received many comments that we should adopt a threshold based on crude capacity as specified in the Clean Air Act and used in past EPA fuel

programs.

In the lead phase-down program for gasoline, we used a definition of ‘‘small refinery’’ that Congress adopted in 1977 specifically for the lead phase-down program. The definition was based on crude oil or feedstock capacity at a particular refinery (less than or equal to 50,000 barrels per calendar day (bpcd)),
combined with total crude oil or feed stock capacity of the refiner that owned the refinery (less than or equal to137,500 bpcd). In 1990, the lead phasedown program was complete and Congress removed this provision from
the Act.

Shortly before the Act was amended in 1990, we set standards for sulfurcontent in diesel fuel, including a twoyear delay for small refineries. We used the same definition of small refinery as we used in the lead phase-down program. This two-year delay, like many
of the small business flexibilities in our gasoline sulfur proposal, was aimed at problems that small refineries faced in raising capital and in arranging for refinery construction.

In the 1990 amendments to the Clean Air Act, Congress rejected this small refinery provision, and instead allocated
allowances to small diesel refineries under the Title IV Acid Rain program. (See CAA Section 410(h).) This approach was also aimed at helping small refineries solve the problem of raising the capital needed to make
investments to reduce diesel sulfur. Congress provided allowances to small
refineries that met criteria similar to that used in the lead phase-down provision—based on the crude oil throughput at a particular refinery,
combined with the total crude oil throughput of the refiner that owned the refinery.

As mentioned above, the CAA
definition was based on crude oil or feedstock capacity at a particular refinery, combined with total crude oil


### 6768 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

92 Company means the business structure of the refinery whether privately or publicly owned. or feed stock capacity of the refiner that owned the refinery (less than or equal to 137,500 bpcd). However, given the mergers, acquisitions, and other changes that have transpired throughout the refining industry in the past few years, we believe the appropriate boundary today is a corresponding corporate crude capacity less than or equal to 155,000 bpcd.

Therefore, in consideration of the above, a refiner must meet both of the following criteria to qualify for the special small refiner provisions
described in the next section: • No more than 1500 employees corporate-wide, based on the average number of employees for all pay periods from January 1, 1998 to January 1, 1999;
and

• A corporate crude capacity less than or equal to 155,000 bpcd for 1998.

ii. Standards That Small Refiners Must

Meet

Upon careful review of the comments received on the proposal as well as the recommendations of the SBAR Panel, we have determined that regulatory relief in the form of delayed compliance dates is appropriate to allow small refiners, both foreign and domestic, to comply with our regulations without disproportionate burdens. From 2004 to 2007, when U.S. refiners must meet the
30/80 standard or the standards listed in Table IV.C–1 if they are participating in our ABT program, refiners meeting the corporate employee and capacity limits prescribed above are allowed to comply with somewhat less stringentrequirements. These interim annualaverage standards for qualifying small
refiners are shown in Table IV.C–3
below.



### TABLE 

### IV.C–3.—T EMPORARY 

### G ASOLINE 

### S ULFUR 

### R EQUIREMENTS FOR 

### S MALL 

### R EFINERS IN 

### 2004–2007

Refinery baseline sulfur level (ppm) Temporary Sulfur Standards (ppm)

Average Cap

0 to 30 ................................................................ 30 ppm .................................................. ........... 300 ppm.

31 to 200 ............................................................ Baseline Level ............................................ ...... 300 ppm. 201 to 400 .......................................................... 200 ppm .................................................... ....... 300 ppm.
401 to 600 .......................................................... 50% of baseline ............................................ ... Factor of 1.5 times the average standard.

601 and above ................................................... 300 ............................................................ ....... 450.

The cap standards for the first two ‘‘bins’’ of refineries (that is those with
baseline sulfur levels from zero to 30 and 31 to 200) have been relaxed somewhat from the proposal based on comments that the proposed standards for these two bins were more stringent than the options under discussion for all
other refiners. We believe that these
small refiners should be able to meet the average standards without much, if any, change to their operations but the more lenient cap will give them some flexibility for turnarounds or unexpected equipment ‘‘upsets’’.

Compliance with the standards in
Table IV.C–3 is based on a refiner’s demonstration that it meets our specific
small refiner criteria. Refiners who qualify as a small refiner under our
definition must establish a sulfur baseline for each of their participating refineries. The following sections explain these requirements in more detail to supplement the information presented above. We also explain how small refiners can apply for an extension of up to two additional years of the applicable small refiner standards, based on a variety of factors such as technology availability or financial hardship.

iii. How Do Small Refiners Apply for Small Refiner Status?

Refiners seeking small refiner status under our gasoline sulfur program must apply to us in writing no later than December 31, 2000, requesting this status. This application for small refiner status must contain the information
described below.

Companies 92 seeking small refiner status must provide us with the following information:

Employment Information

• A listing of the name and address of each location where any employee of the company worked during the 12 months preceding January 1, 1999.

• The average number of employees at each location based upon the number of employees for each of the company’s pay periods for the 12 months preceding January 1, 1999.

• The type of business activities
carried out at each location.

Crude Capacity Information

• The total corporate crude oil capacity of the refiner as reported to the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE).

For refineries owned by joint ventures, the total employment of both (all) companies must be considered in determining whether the 1,500 employee limit is met. In addition, a refiner who reactivates a refinery that was shut down or non-operational between January 1, 1998 and January 1, 1999, may apply for small refiner status no later than June 1, 2002. In this case,
we will consider the information provided to determine the correct period for judging compliance with the 1500 threshold. Where appropriate we

will look at the most recent 12 months of employment information.

Refiners seeking small refiner status must also provide us with the total crude capacity of their corporation (the sum of all individual refinery capacities for multiple-refinery companies, including any and all subsidiaries) as reported to EIA for 1998 (published by EIA in 1999). The information submitted to EIA is presumed to be correct. However, in cases where a company disputes this information, we will allow 60 days after the company submits its application for small refiner status for that company to petition the Agency with the appropriate data to

correct the record. For reactivated refineries owned by a small refiner, we will consider the information provided to determine the correct period for judging compliance with the corporate capacity threshold. Where appropriate, we will look at the most recent year of crude capacity information.

If a refiner with approved small refiner status later exceeds the 1,500 employee threshold without merger or acquisition or the corporate capacity of 155,000 bpcd, its refineries could keep their individual refinery standards. This is to avoid stifling normal company growth and is subject to our finding that the company did not apply for and

receive the small refiner status in bad

faith.


### 6769 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

93 Includes batch number, volume, and sulfur content for each batch of gasoline produced in 1997

and 1998. 94 In addition to gasoline produced from crude oil, a small refinery’s baseline volume would include gasoline produced from purchased blendstocks where the blendstocks are substantially transformed using a refinery processing unit. iv. How Do Small Refineries Apply for a Sulfur Baseline?

A qualifying small refiner, domestic or foreign, may apply for an individual sulfur baseline by December 31, 2000 for any refinery owned by the company by providing the following information:

• A calculation of the refinery’s sulfur baseline using its average gasoline
sulfur level based on 1997 and 1998 production data, 93 and

• The average volume of gasoline (including conventional and reformulated) produced in these two

years.

As we proposed, baseline sulfur levels and gasoline volumes are averaged over two years (1997 and 1998) to account for any production-related anomalies that may have occurred in 1997 or 1998. For the overall program, however, we are only using 1997 and 1998 data for the reasons described in Section IV.C.1, above. For any refiner who reactivates arefinery that was shut down or nonoperational between January 1, 1998 and January 1, 1999, we will use the
most recent information available for baseline establishment purposes.

The regulations specify the information to be submitted to support the baseline application. The baseline calculations should include any oxygen added to the gasoline at the refinery. This application would be submitted at the same time the refiner applies for small business status; confirmation of
small business status would not be required to apply for an individual sulfur baseline. Pending refinery baseline approval, we will assign standards to each of the company’s
refineries in accordance with Table

IV.C.–3.

Oxygenate blenders, regardless of their size, are not eligible for the small
refiner individual baselines and standards because they would not experience circumstances similar to those of small refining companies. That is, oxygenate blenders do not have the burden of capital costs to install desulfurization equipment, which is the primary reason for allowing small refiners to have a relaxed compliance
schedule.

v. Volume Limitation on Use of a Small Refinery Standard

Except as noted below, the volume of gasoline subject to a small refinery’s
individual standards is limited to the average volume of gasoline the refinery produced from crude oil during the baseline years (1997 and 1998), excluding the volume of gasoline produced using blendstocks produced at another refinery and exports. 94 Under this approach, the baseline volume for a small refinery would reflect only the volume of gasoline produced from crude oil during the 1997 and 1998 baseline

years.

However, to ensure that the overall sulfur in gasoline from small refiners does not greatly increase under the
terms of the small refiner extension and result in overall gasoline pool sulfur levels higher than anticipated, the volume would be limited beginning in 2004 to the volume of gasoline that is the lesser of: (1) 105 percent of the baseline volume, or (2) the volume of gasoline produced during the year from crude oil. Any volume of gasoline produced during an averaging period in excess of this limitation is subject to the corporate average standards that apply to all other refiners (i.e., the corporate average standards listed in Table IV.C.– 1).

In 2006 and 2007, the refinery averages of Table IV.C.–1 will apply. In this case, the small refinery’s annual average standard will be adjusted based
on the excess volume in a manner similar to the compliance baseline equation for conventional gasoline under Section 80.101(f) of Part 40 of the Code of Federal Regulations. However, the small refinery’s per-gallon cap standard will not be adjusted.

This limitation assures that small refineries receive relief only for gasoline produced from crude oil, that is the portion of the refinery operation requiring capital investment to meet
lower sulfur standards.

vi. Extensions Beyond 2007 for Small Refiners

Beginning January 1, 2008, all small companies’ refineries must meet the national sulfur standard of 30 ppm on average and the 80 ppm cap, except
small refineries under IV.C.2.i. that apply for and receive an extension of their small refiner status and unique standards. An extension will provide a given small refinery up to an additional two years to comply with the national
standards. An extension must be requested in writing and must specify the factors that demonstrate a significant economic hardship to qualify the refinery for such an extension. Factors
considered for an extension could include, but are not limited to, the refinery’s financial position; its efforts to procure necessary equipment and to obtain design and engineering services and construction contractors; the availability of desulfurization equipment, and any other relevant
factors.

In order for us to consider an extension, a refiner must submit a detailed request for an extension by January 1, 2007, demonstrating that it has made best efforts to obtain necessary financing, and must provide detailed information regarding any lack of success in obtaining financing. This information shall include, but may not be limited to copies of loan applications for the necessary financing for the construction of appropriate sulfur reduction technology as well as the application of financing for other equipment procurements or improvements in this time frame. If financing has been disapproved or is otherwise unsuccessful, the refiner shall provide documents supporting the basis for that disapproval and evidence of efforts to pursue other means of financing. If we determine that the
refiner has made the best efforts possible to achieve compliance with the national standards by January 1, 2008,
but has been unsuccessful for reasons beyond its control, we will consider granting the hardship extension initially for the 2008 averaging period. If further relief is appropriate for good reasons,
we will consider a further extension through the 2009 averaging period but in no case will this relief be provided
unless the refiner can demonstrate conclusively that it has financing in place and that it will be able to complete construction and meet the national gasoline sulfur standards no later than December 31, 2009.

Compliance Plans for Demonstrating a Commitment To Produce Low Sulfur
Gasoline

This final rule includes a compliance plan provision for those refiners who may seek a hardship extension of their approved interim standards. This provision requires that those refiners with approved interim standards who seek a hardship extension must submit a series of reports to EPA discussing and describing their progress toward producing gasoline that meets the 30/80 ppm standards by January 1, 2008. We expect that small refiners will need to begin preparations to meet the national standards in 2008 by 2004. However, we understand that the potential exists for
some small refiners to face additional hardship circumstances that will
warrant more time to meet the standards. For this reason, we have adopted provisions (see above) allowing


### 6770 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

95 If a refinery has a baseline sulfur level higher than 120 ppm (as described below in IV.C.1.c.v.), then credits are generated from the baseline to 120 ppm and allotments from 120 ppm to the new sulfur level (and discounted 20 percent if applicable). refiners subject to the interim standards to petition us and make a showing that
additional time is needed to meet the national standards. To properly evaluate these hardship applications, we are requiring demonstrations of good faith efforts towards assessing the economic feasibility, along with the business and technical practicality of ultimately producing low sulfur gasoline. Such progress reports must be submitted for a refiner to receive consideration in any future determinations regarding hardship extensions. However, these reports are not required from refiners who will not be seeking a hardship

extension.

By June 1, 2004, such refiners would need to submit preliminary information in the form of a report outlining its time line for compliance and a project plan discussing areas such as permits, engineering plans ( e.g., design and construction), and capital commitments for making the necessary modifications to produce low sulfur gasoline. Documents showing activities and progress in these areas should be provided if available.

By no later than June 1, 2005, these
small refiners would need to submit a report to us stating in detail progress to date based on their time line and project plan. This should include copies of approved permits for construction of the equipment, contracts for design and construction, and any available evidence of having secured the necessary financing to complete the required construction. If any difficulties in meeting this requirement are anticipated, the refiner must submit a detailed report of all efforts to date and the factors that may cause delay, including costs, specification of engineering or other design work still needed and reasons for delay, specification of equipment needed and any reasons for delay, potential equipment suppliers and history of negotiations, and any other relevant information. If unavailability of equipment is a factor, the report must include a discussion of other options considered, and the reasons these other options are not feasible.

In addition, the small refiner would need to provide evidence by June 1, 2006, that on-site construction has begun at its refinery(s) and that absent unforeseen circumstances or problems, they will be producing complying gasoline (30/80 ppm) by January 1,
2008. While the submission of these progress reports is evidence of a refiner’s good faith efforts to comply by 2008, it does not bind the refiner to make gasoline in 2008. There are several reasons why a refiner may choose to exit the gasoline-production business in 2008 that go beyond the low sulfur gasoline requirement.

As a result of a refiner’s efforts in moving toward compliance with the 2008 standards, for market, economic, business, or technical reasons, the company could choose not to make gasoline in 2008. Although we do not believe this will be the likely outcome for small refiners, we cannot preclude it. Any refiner that makes such a determination in its progress reports
will have until 2008 to transition out of gasoline production, but will not be considered for a extension of hardship
relief.

vii. Can Small Refiners Participate in the ABT Program?

As described in IV.C.1.c.i above, any refinery (including those owned by small refiners) can generate sulfur allotments (in ppm-gallons) in 2003 by producing gasoline containing less than 60 ppm sulfur on an annual-average basis. Once this 60 ppm trigger is reached, allotments will be calculated
based on the amount of reduction from 120 ppm 95 . However, these allotments may be discounted depending on the actual sulfur level. If a refinery fully demonstrates compliance by producing gasoline with an annual average sulfur level of 0 to 30 ppm, the allotments retain their full value—they are not
discounted at all. For actual sulfur levels of 31–60 ppm, which are indicative of a partial demonstration,
the allotments are discounted 20 percent.

During the period 2000–2003, refineries owned by small refiners can also generate credits by producing gasoline averaging at least 10 percent lower than that refinery’s baseline sulfur level. In other words, to generate credits, the refinery’s annual average sulfur level for all of its gasoline on average must be 0.9 × (baseline sulfur level). Once this ‘‘trigger’’ is reached,
credits will be calculated based on the amount of reduction from the refinery’s sulfur baseline. For example, if in 2002 a refinery reduced its annual average sulfur level from a baseline of 450 ppm to 150 ppm (well below the trigger of 0.9

× 450 = 405 ppm), its sulfur credits
would be determined based on the difference in annual sulfur level (450— 150 = 300 ppm) multiplied by the volume of gasoline produced in 2002. Similarly, small foreign refiner-owned refineries with an individual sulfur baseline can generate credits in these years as long as the annual average sulfur level of the gasoline exported to the U.S. from that refinery is lower than 90 percent of the baseline sulfur level.

During the period 2004–2007, refineries owned by small refiners will be permitted to generate credits but only
if their actual annual sulfur level of all gasoline produced or imported averages below their refinery standard, and only
for the difference between the standard and the actual annual sulfur average.

A refinery (owned by a small refiner) wishing to participate in the ABT program can sell credits beginning as soon as January 1, 2000 but may wait until December 31, 2000 to apply for small refiner status. However, the standards assigned to that refinery (as presented in Table IV.C–3 above) will be
based on the sulfur level from which credits were generated, not the baseline sulfur level, since the refiner would have already demonstrated the ability to
meet the lower sulfur level. For compliance purposes and to give refineries certainty regarding the gasoline sulfur standards to which they will be held during 2004–2007, the standards for a small refiner refinery participating in ABT will be set based on the refinery’s lowest sulfur average for any year between 1999 and 2003.

Using the example above, a refinery (owned by a refiner with small refiner status) with a 1997–98 baseline sulfur level of 450 ppm would have an interim average standard of 450/2 = 225 ppm and a cap of 225 × 1.5 = 338 ppm. If that refinery generated 300 sulfur credits in 2002 by producing gasoline with 150 ppm sulfur, then that refinery’s average
sulfur standard for 2004–2007 would be ratcheted down to 150 ppm with a cap of 300 ppm. However, that refinery
would still be able to use the 300 credits that it had generated and banked in 2002 for compliance with its 150 ppm
standard.

Based on the comments received on our proposal, we are allowing small
refineries to use credits and/or allotments that they generated and/or to purchase credits and/or allotments from another refinery to meet their average standard during 2004–2007. We
solicited comment on whether small refiners subject to the interim standards should be permitted to use credits towards meeting those standards, and several small refiners who already produce very clean gasoline commented that the special small refiner standards do not benefit them in any way. These refiners argued that if they could generate sufficient sulfur credits in 2000–2003, or could obtain such credits


### 6771 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

through purchases from other refiners, they would not participate in the small refiner program but would instead participate in the sulfur ABT program. But since they are not positioned to generate credits (due to their already low sulfur levels), and have little certainty of being able to purchase credits, they need the relief provided by the small refiner provisions. We concur with these concerns and thus permit
small refiners to use ABT credits and allotments. Small refiners may only use
ABT credits and/or allotments to comply with their refinery average standard, not the per-gallon caps applied to their gasoline.

At any time, a small refiner can choose to ‘‘opt out’’ of the small refiner program and, beginning the next calendar year, comply with the
standards in Table IV.C–2. The refiner would have to notify us of this change in its compliance program. Once a small refiner leaves the small refiner program,however, it would not be eligible to reenter the small refiner program.

b. Temporary Waivers From Low Sulfur Requirements in Extreme Unforeseen

Circumstances

In the final rule, EPA is adopting a provision permitting refiners to seek a temporary waiver from the sulfur
standards in certain circumstances. Such waivers will be granted at EPA’s discretion. Under this provision a refiner may seek permission to distribute gasoline that does not meet the applicable low sulfur standards for a brief time period, based on the refiner’s inability to produce complying gasoline because of extreme and
unusual circumstances outside the
refiner’s control that could not have been avoided through the exercise of due diligence. This provision is similar to a provision in EPA’s RFG regulations, and is intended to provide refiners short-term relief in unanticipated
circumstances such as an accidental refinery fire or a natural disaster. The short-term waiver provision is intended to address unanticipated circumstances that cannot be reasonably foreseen at
this time or in the near future

The conditions for obtaining such a
waiver that are similar to those in the RFG regulations. These conditions are necessary and appropriate to ensure that any waivers that are granted are limited in scope, and that refiners do not gain
economic benefits from a waiver. Therefore, refiners seeking a waiver
must show that the waiver is in the public interest, that the refiner was not able to avoid the nonconformity, that it will make up the air quality detriment associated with the waiver, as well as any economic benefit from the waiver, and that it will meet the applicable sulfur standards as expeditiously as possible.

c. Temporary Waivers Based on Extreme Hardship Circumstances

In addition to the provision for shortterm relief in unanticipated circumstances, we are adopting a provision for relief based on extreme hardship circumstances. In developing our sulfur program, we considered whether any refiners would face particular difficulty in complying with the standards in the lead time provided. As described in Section IV.C.2.a., we concluded that refineries owned by small businesses would experience more difficulty in complying with the standards on time because, as a group, they have less ability to raise capital necessary for refinery investments, face proportionately higher costs because of economies of scale, and are less able to successfully compete for limited engineering and construction resources. However, it is possible that other
refiners who do not meet our criteria for
the interim standards also face particular difficulty in complying with the sulfur standards on time. Therefore, we are including in the final rule a provision allowing us, at our discretion, to grant temporary waivers from the sulfur standards based on a showing of extreme hardship circumstances. We do not anticipate, nor do we expect there is a need for, granting temporary waivers that apply to more than approximately one percent of the national gasoline pool in any given year. This provision would allow refiners (domestic and foreign) to request a
waiver from the sulfur standards based on a showing of unusual circumstances that result in extreme hardship and significantly affect the ability to comply by the applicable date. As with the small refiner interim standards, this provision furthers our overall environmental goals of achieving low sulfur gasoline nationwide as soon as possible. By providing short-term relief
to those refiners that need additional time because they face hardship circumstances, we can adopt a program that reduces gasoline sulfur beginning in 2004 for the majority of the industry that can comply by then.

As described above, EPA understands that this program will require significant economic investments by the refining industry. We have adopted a program with sufficient flexibilities (including an ABT program, allotment trading, a geographic phase-in, and interim standards for qualifying small refiners)
to make these investments reasonable and feasible over the time frame in which the standards are phased in. Because the refining industry encompasses a wide variety of individual circumstances, and our program phases in based on the lead
time we believe is reasonable for the industry as a whole, there may be unusual circumstances that impose extreme hardship and significantly affect an individual refinery’s ability to comply in the lead time provided. However, we do not intend for this waiver provision to encourage refiners to delay planning and investments they would otherwise make in anticipation of receiving relief from the applicable requirements. In addition, we want to limit the environmental impact of any hardship waivers from compliance with the standards. Thus, we anticipate that hardship waivers will only be granted in

rare circumstances.

Because of the significant environmental benefits of lowering sulfur in gasoline, we will administer this provision in a manner consistent with continuing to ensure the environmental objectives of the regulation. In our analysis of the interim small refiner standards, we concluded that only a minimal portion of the national gasoline pool would potentially be impacted by the less stringent interim standards, due to the relatively small production volume of these facilities. To limit the potential environmental impact of this hardship provision, we reserve the discretion to deny applications where we find that granting a waiver would result in an unacceptable environmental impact.
While this determination will be made on a case-by-case basis, we do not expect there is a need for, nor do we anticipate, granting waivers that apply to more than approximately one percent of the total national pool of gasoline in any given year, or to more than a minimal percentage of the gasoline supply of an area known to have significant air quality problems.

There are several factors we will consider in evaluating a petition for additional time to comply. This could include refinery configuration, severe economic limitations, and other factors that prevent compliance in the lead time provided. Applications for a waiver
must include information that will allow us to evaluate all appropriate
factors. EPA will consider whether the refinery configuration or operation is unique or atypical, how much of a refinery’s gasoline is produced using an FCC unit, its hydrotreating capacity relative to its total crude capacity, total reformer unit throughput capacity relative to total production, gasoline


### 6772 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

production in proportion to other refinery products, and other relevant factors. A refiner may also face severe
economic limitations that result in a demonstrated inability to raise capital to make necessary investments to comply in time, which can be shown by an unfavorable bond rating, inadequate resources of the refiner and its parent and/or subsidiaries, or other relevant factors. In addition, we will look at the total crude capacity of the refinery and its parent corporation. Finally, we will consider where the gasoline will be sold in evaluating the environmental impacts of granting a waiver.

This provision is intended to address unusual circumstances that we expect
will be foreseeable now or in the immediate future, such as unique and atypical gasoline refinery operations or a demonstrated inability to raise capital.
These kinds of circumstances should be apparent at this time or in the near future, so refiners seeking additional time under this provision must apply for relief by September 1, 2000. A refiner seeking a waiver must show that unusual circumstances exist that impose extreme hardship and significantly affect its ability to meet the standards on time, and that it has made best efforts to comply with the standards, including
efforts to obtain credits and/or allotments towards compliance. Applicants for a hardship waiver must also submit a plan demonstrating how
the standards will be achieved as expeditiously as possible. In submitting the plan, it must include a timetable for obtaining the necessary capital, contracting for engineering and construction resources, and obtaining permits. EPA will review and act on applications, and, if a waiver is granted, will specify a time period, not to extend beyond January 1, 2008 (the date by which all gasoline is expected to meet the 30 ppm refinery average and 80 ppm per gallon cap standards), for the

waiver.

If a waiver is granted, EPA will impose as a condition of the waiver other reasonable requirements, including antibacksliding requirements
to ensure no deterioration in the sulfur level of gasoline and interim sulfur
standards that the refiner must meet. This is appropriate since some refiners who may qualify for a waiver can achieve some sulfur reductions, and even reductions to levels above 30 ppm
will result in some environmental benefits. While this provision allows EPA to waive the per gallon standards as well as the average standards, EPA would not allow gasoline sulfur to exceed the highest per gallon cap applicable to a refiner under the interim small refiner standards described in Section IV.C.2. Once all applications have been received, EPA will consider the appropriate process to follow in reviewing and acting on applications, including whether to conduct a notice and comment decision-making process.

3. Streamlining of Refinery Air Pollution Permitting Process

a. Brief Summary of Proposal

Industry commenters expressed concern over the ability to obtain permits to construct and operate the facility modifications needed to meet the Tier 2 rule requirements by the end of 2004. As part of the preamble to the proposed rule, we outlined possible approaches to provide greater certainty and to expedite potentially applicable permit processes. In general, we
solicited comments on whether and how policy options might be designed so as to exempt Tier 2 projects from major New Source Review (NSR) and/or to expedite the processing of permits where such requirements would apply. In particular, we solicited comment on whether the major NSR process could be expedited if: (1) EPA provided guidance
on Lowest Achievable Emission Rate (LAER) requirements or Best Available Control Technology (BACT) determinations; (2) emissions
reductions could be made available or designated for offsetting Tier 2 activities; (3) EPA developed model permits, or (4) EPA assisted the States in resolving source-specific permitting issues as they would arise. The Agency
also solicited comments on how the title V operating permit requirements, where applicable, might need to be integrated with the relevant NSR process.

In proposing various mechanisms to expedite the permitting of Tier 2 projects, we recognized that a combination of measures might be needed, since the situations could vary widely among individual refineries due
to differences in such factors as available equipment capacity, amount of sulfur in the crude oil, and applicable State regulations. Source-specific analyses are also necessary to establish what sulfur reduction techniques can be applied, to determine the applicable permitting requirements, and to evaluate what controls will be necessary as a result of these requirements. We
indicated our intent to offer assistance
where needed.

b. Significant Comments Received

The most significant comments received on the proposal concerning the timing impacts due to air permit requirements are presented below. These commenters focused exclusively on the requirements to obtain a preconstruction permit under the NSR program. Generally, commenters only concerns regarding the title V operating permit program were that the States’ ongoing efforts to issue these permits might create a backlog which could delay the issuance of NSR permits for Tier 2 projects. A more detailed
discussion of comments received on the proposal and EPA’s response are contained in the Response To
Comments document and is filed in the
Docket for this action.

We received written and oral
comments from refineries about the permit requirements associated with Tier 2 projects. Refiners emphasized the need for certainty. They pointed out the need to secure preconstruction permits within 18 months ( e.g., 6 months to prepare and file NSR applications and another 12 months to issue the permit) and the need for permitting authorities to commit appropriate resources to meet
this time frame. State and local air pollution control agencies did not support providing exemptions from emissions control and permitting requirements. Rather, agency commenters stated that they could accomplish the permitting requirements in the necessary time frames, provided that complete permit applications were received in a timely manner and refiners conferred with their regulatory agencies soon after the Tier 2 requirements are promulgated. They also indicated that the major NSR process could be expedited and have more certainty (i.e., permits could be processed in 6 to 9 months) if EPA would provide guidance on emissions controls, emissions monitoring, and offsets. In general, environmental and community groups pointed out that the remedies under traditional permitting practices should
be exhausted before additional flexibility is granted for Tier 2 projects.

c. Today’s Action

Based on the comments and other information received in response to the proposal, EPA believes that it is not necessary or appropriate to explore further the development of possible options which would exempt Tier 2 projects from the normally applicable preconstruction review process. This position is supported by: (1) The comments of States that industry can, in general, apply and receive NSR permits in time to comply with Tier 2; and (2) the recognition of industry’s potential ability to use emissions reductions to net Tier 2 projects out of major NSR which would otherwise be applicable. Nonetheless, we believe that actions


### 6773 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

should be taken to facilitate early compliance, to add certainty to the anticipated permitting actions and schedules, and to minimize the possibility of delay. Accordingly, EPA is taking two types of actions to promote these objectives.

First, as previously discussed, we have structured the final gasoline sulfur program to allow additional lead time for many refiners (i.e., certain refineries
would be able to make desulfurization changes later than the proposed 2004 compliance date to meet Tier 2 requirements). This approach will help
address the concerns over the availability of necessary new equipment and permitting backlogs caused by many refineries acting to obtain permits and order equipment within relatively the same time period.

Second, we intend to take several actions (described in more detail below) to expedite and impart greater certainty in obtaining necessary major NSR permits. As a result of comments received on the proposal, and the lead time provided in the final gasoline sulfur program, we believe that the vast majority of permits can be issued within the necessary time frames, provided that refineries submit their preconstruction applications in a timely manner and regulatory authorities prioritize the issuance of these permits. We also
intend to assist States and refiners on a case-by-case basis in their efforts to address any unique permitting problems that might arise and, thus, remedy potential problems that could cause unanticipated delays. In the unlikely event permitting delays occur, EPA will
work with refiners and the state/local permitting agencies on a case-by-case basis, where a refinery has unique circumstances that necessitate unique

treatment.

While today’s strategy will help expedite the permitting process, refineries that trigger major NSR as a result of producing low sulfur gasoline will still have to install the stringent level of emissions control technology required by the Act. However, we intend to issue guidance to assist states in making decisions about the levels of control technology, as described more below. In addition, the Agency wishes to clarify that, in our efforts to provide greater certainty and to facilitate more expeditious permitting, we are in no way shortcutting existing opportunities for public participation. We recognize the importance of public participation in making permitting decisions and intend that the measures adopted to address permitting concerns will not diminish the opportunities for public participation. i. Major New Source Review
The major NSR program, as it applies to existing major stationary sources of air pollution, requires that a preconstruction permit be issued before a source makes a physical change or change in its method of operation of any project that would result in a significant
net emissions increase. As described in the proposal, the steps taken by certain refineries to implement gasoline sulfur reductions to meet today’s rule could
result in emissions increases in one or more pollutants which may trigger the requirements for this type of preconstruction permit. A number of the refineries are located in areas designated
as nonattainment for at least one pollutant. The nonattainment NSR requirements pursuant to part D of the Act would apply to any such refinery undergoing a major modification. For
those refineries located in attainment or unclassifiable areas, permit requirements for the prevention of significant deterioration (PSD) of air quality must be met for major
modifications.

The EPA recognizes the importance of timely major NSR (as applicable) permit actions for refineries to proceed with necessary changes to meet the new low sulfur gasoline standard. We encourage refineries to begin discussions with permitting authorities and to submit permit applications—as early as possible. In addition, based on comments received, we believe that there are a few key areas in which
assistance would be useful toward helping States issue timely permits to the applicable refineries:

• Federal guidance on emissions control technology requirements.

Refineries subject to major NSR review will be required to undergo a source-specific evaluation to apply either BACT or LAER, depending upon the applicable program requirements. For example, the evaluation for BACT is case-by-case and takes into account the alternative technologies available to control pollution from a particular emissions unit or process, and considers the energy, environmental, economic
and other costs associated with each technology. We intend to issue guidance setting out a level of emissions that, in our view, would be expected to satisfy the requirements for BACT for certain emissions units associated with refinery desulfurization projects. While States would not be required to use the results to establish BACT for a particular refinery subject to review and EPA’s guidance on a control technology may not be appropriate where there exists unusual site-specific circumstances, such guidance would add the certainty of EPA’s expectations.

Since negotiation of an appropriate
BACT level often is one of the most time consuming aspects of permitting, we believe this EPA guidance will significantly expedite the process. The federal guidance on BACT, by including an evaluation of the most stringent control levels currently being achieved or required, will also provide federal guidance on LAER. The EPA plans to make a draft of this guidance available for public review and comment in January 2000. Final guidance would then be prepared, after relevant comments are considered, in time for States, refiners, and the public to consider in preparing and reviewing permit applications and proposed permits.

• Availability of offsets

. Refineries located in nonattainment areas must offset any proposed significant emissions increases with an equal or greater amount of emissions reductions from other sources, usually coming from within the same
nonattainment area. We believe that vehicle emissions reductions resulting from the use of low sulfur gasoline can be used as offsets for the refineries, as long as the statutory and regulatory
criteria for creditable offsets are satisfied and States decide to provide for this opportunity in their SIP attainment demonstration. We believe generally that this option should be available to States since only a small fraction of the
total vehicle emissions reductions in any county would be needed to offset refinery emissions increases resulting from implementation of gasoline desulfurization projects. Generally, the
reductions must also occur in the same
nonattainment area as the location of the refinery for which the offsets are required. The EPA plans to issue the appropriate guidance early in the year 2000 to help a State to determine whether and to what extent it may wish
to use vehicle emissions reductions as offsets for Tier 2 projects.

• EPA refinery permitting teams. We intend to assemble special EPA teams, comprised of Headquarters and Regional Office experts, that will track the overall progress in permit issuance
and will be available to assist State and local permitting authorities, refineries, and the public upon request to resolve site-specific permitting issues. These teams will be comprised of persons who are knowledgeable about permitting programs and refinery operations and can provide expert assistance to troubleshoot permitting issues that may arise. As appropriate, the teams willwork with stakeholders on a case-byVerDate 27<JAN>2000 21:29 Feb 09, 2000 Jkt 190000 PO 00000 Frm 00077 Fmt 4701 Sfmt 4700 E:\FR\FM\10FER2.SGM pfrm08 PsN: 10FER2

### 6774 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

96 The NEJAC was chartered in 1993 expressly to give the EPA Administrator independent advice, consultation, and recommendations on environmental justice matters. NEJAC members come from state, tribal, and local governments; tribal and indigenous citizen’s organizations; business and industry; academia; and environmental advocacy and grassroots community

groups. case basis to evaluate site-specific approaches to regulatory compliance within existing policy and regulations.

ii. Environmental Justice

The Tier 2/gasoline sulfur rule will help achieve significant nationwide reductions in the emissions of nitrogen oxides (NOx), volatile organic compounds (VOC), particulate matter (PM), and sulfur dioxide (SO 2). These reductions will improve air quality across the country and will provide increased protection to the public against a wide range of health effects, including chronic bronchitis, respiratory illnesses, and aggravation of asthma symptoms. Furthermore, the Tier 2/gasoline sulfur rule will achieve
environmental benefits in the local areas where refineries are located, due to reductions in tail pipe emissions from vehicles driven in those areas. Although we expect residual emissions increases at some refineries even after installing the stringent level of emissions controls required under the Act, for the vast majority of areas, we believe that these potential refinery emissions increases will be very small compared to the Tier
2 benefits in those same local areas.

We believe it is important to
understand and address concerns relating to potential localized emissions
increases from refineries that make significant process changes to meet the requirements of the Tier 2 rule. We believe that, among other things, the keys to addressing any potential
concerns are as follows:

• Providing meaningful community involvement early and throughout the

process;

• Determining what information and actions would eliminate concerns; and

• Determining what EPA, States, and industry can do to make the permitting process smoother by ensuring ongoing community involvement in the decision making process and by building trust among stakeholders.

To this end, the Agency has already taken some actions to try to mitigate potential environmental justice concerns. First, EPA’s Office of Air and Radiation and the Alternative Dispute
Resolution Team within EPA’s Office of the Administrator implemented a national convening process which was designed to bring together a broad spectrum of stakeholders to explore with them their perceptions and views
of issues associated with Tier 2 permitting and to assess the potential for a collaborative process to address specific implementation issues at some time in the future. The convening was carried out by an outside neutral party
who conducted interviews with representatives from selected EPA offices, States, industry, environmental groups, and environmental justice organizations. Second, EPA held informational briefings and provided background materials to the National Environmental Justice Advisory Council’s (NEJAC) 96 Air and Water
Subcommittee and Enforcement Subcommittee to provide an opportunity for them to provide
feedback and recommendations to the Agency. Finally, in October 1999, we
met with both national environmental groups and environmental justice advocacy representatives, to discuss their views on the permitting aspects of the proposed rule.

The EPA is committed to continue working with all stakeholders to resolve specific Environmental Justice issues if and when they arise. To fulfill this commitment, we plan to undertake additional actions in the future, including providing education and outreach about the rule and its impacts in local communities, developing permitting guidance through a public process and addressing Title VI petitions if they arise.

D. What Are the Economic Impacts, Cost Effectiveness and Monetized Benefits of the Tier 2 Program?

Consideration of the economic impacts of new standards for vehicles and fuels has been an important part of our decision making process for this final rule. The following sections
describe first the costs associated with meeting the new vehicle standards and
the new fuel standards. This will be
followed with a discussion of the cost effectiveness of the rule. Lastly, we will
discuss the results of a benefit-cost assessment that we have prepared.

Full details of our cost analyses, including information not presented here, can be found in the RIA associated with this rule. Also, our response to comments on the cost, cost effectiveness, and monetized benefits analyses are contained in the Response
to Comments document for this rule.

1. What Are the Estimated Costs of the
Vehicle Standards?

To perform a cost analysis for the standards, we first determined a package of likely technologies that
manufacturers could use to meet the standards and then determined the costs of those technologies. In making our
estimates we have relied on our own technology assessment which included publicly available information, such as that developed by California, as well as confidential information supplied by individual manufacturers, and the results of our own in-house testing.

In general, we expect that the Tier 2 standards will be met through
refinements of current emissions control components and systems rather than through the widespread use of new technology. Furthermore, smaller lighter-weight vehicles and trucks will generally require less extensive improvements than larger vehicles and trucks. More specifically, we anticipate a combination of technology upgrades such as the following:

• Improvements to the catalyst system design, structure, and formulation plus in some cases an increase in average catalyst size and loading;

• Air and fuel system modifications including changes such as improved microprocessors, improved oxygen sensors, leak free exhaust systems, air assisted fuel injection, and calibration changes including improved precision fuel control and individual cylinder fuel control;

• Engine modifications, possibly including an additional spark plug per cylinder, an additional swirl control valve, or other hardware changes
needed to achieve cold combustion stability;

• Increased use of fully electronic exhaust gas recirculation (EGR); and

• Increased use of secondary air injection for 6 cylinder and larger engines.

The costs for MDPVs have been
included here with the LDT4 cost estimates. We expect that the technologies needed to meet the Tier 2 standards for the MDPVs will be very similar to those for LDT4s. However, the
MDPVs cost estimates are somewhat higher than for LDT4s. Vehicles over 8,500 pounds GVWR are currently certified to heavy-duty engine emissions standards using the heavy-duty test procedures. This, at least in part, has led to differences in baseline technologies compared to current LDT4s. Vehicles above 8,500 pounds, for example, are currently equipped with technologies such as close coupled catalysts and secondary air injection to a lesser extent. Therefore, we expect higher
incremental costs for the MDPVs compared to LDT4s. There is further
information on the costs for MDPVs in
the RIA.


### 6775 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

97 ‘‘Learning Curves in Manufacturing,’’ Linda Argote and Dennis Epple, Science, February 23, 1990, Vol. 247, pp. 920–924. 98 Even though the NLEV program ends in the
Tier 2 timeframe, we have not included the NLEV program costs or benefits in our analysis, since EPA analyzed and adopted NLEV previously. Using a typical mix of changes for each group, we projected costs separately for LDVs, the different LDT classes, and for different engine sizes (4, 6, 8, 10-cylinder) within each class. For each group we developed estimates of both variable costs (for hardware and assembly time) and fixed costs (for R&D, retooling, and certification).

Cost estimates based on the current projected costs for our estimated technology packages represent an expected incremental cost of vehicles in the near-term. For the longer term, we
have identified factors that would cause cost impacts to decrease over time. First,
since fixed costs are assumed to be recovered over a five-year period, these costs disappear from the analysis after the fifth model year of production. Second, the analysis incorporates the expectation that manufacturers and suppliers will apply ongoing research and manufacturing innovation to making emission controls more effective and less costly over time. Research in the costs of manufacturing has consistently shown that as manufacturers gain experience in production and use, they are able to apply innovations to simplify machining and assembly operations, use lower cost materials, and reduce the number or complexity of component parts. 97 These reductions in production costs are typically associated with every doubling of production volume. Our analysis incorporates the effects of this ‘‘learning curve’’ by projecting that the variable costs of producing the Tier 2 vehicles decreases by 20 percent starting with the third year of production. We applied the learning curve reduction only once since, with existing technologies, there would be less opportunity for lowering production
costs than would be the case with the adoption of new technology.

We have prepared our cost estimates for meeting the Tier 2 standards using a baseline of NLEV technologies for LDVs, LDT1s, and LDT2s, and Tier 1, or current technologies for LDT3s, LDT4s
and MDPVs. These are the standards that vehicles would be meeting in

2003. 98 We have not specifically analyzed smaller incremental changes to technologies that might occur due to the
interim standards between the baseline and Tier 2. In most cases, we believe these changes will not be significant
based on current certification levels andmanufacturers will maximize carryover. For others, manufacturers can use averaging and other program flexibilities to avoid redesigning vehicles twice within a relatively short period of time. We believe this is likely to be an attractive approach for manufacturers due to the savings in R&D and other

resources.

For the total annual cost estimates, we projected that manufacturers will start the phase-in of Tier 2 vehicles with LDVs in 2004 and progress to heavier
vehicles until all LDT2s meet Tier 2
standards in 2007. For LDT3s and LDT4s, we projected some sales of Tier 2 LDT3s prior to 2008 for purposes of averaging in the interim program and that the phase-in of Tier 2 vehicles
would end with LDT4s and MDPVs in

2009.

Finally, we have incorporated what we believe to be a conservatively high level of R&D spending at $5,000,000 per vehicle line (with annual sales of 100,000 units per line). We have included this large R&D effort because calibration and system optimization is likely to be a critical part of the effort to meet Tier 2 standards. However, we believe that the R&D costs may be generous because the projection ignores the carryover of knowledge from the first vehicle lines designed to meet the standard to others phased-in later.

The evaporative emissions standards we are finalizing today for LDVs, LDTs and MDPVs are feasible with relatively small cost impacts. We estimate the cost of system improvements to be about $4 per vehicle, for all vehicle classes. This
incremental cost reflects the cost of moving to low permeability materials, improved designs or low-loss connectors. R&D for the evaporative
emissions standard is included in the R&D estimates given above for the tailpipe standards. We have included no projections of learning curve reductions for the evaporative standard.

Table IV.D.–1 provides our estimates of the per vehicle increase in purchase price for LDVs, LDTs, and MDPVs. The
near-term cost estimates in Table IV.D.– 1 are for the first years that vehicles meeting the standards are sold, prior to
cost reductions due to lower productions costs and the retirement of fixed costs. The long-term projections
take these cost reductions into account. We have sales weighted the cost differences for the various engine sizes (4-, 6-, 8-, 10-cylinder) within each
category.



### TABLE 

### IV.D.–1.—E STIMATED 

### P URCHASE 

### P RICE 

### I NCREASES 

### D UE TO 

### T IER 

### 2 TAILPIPE 

### STANDARDS

LDV LDT1 LDT2 LDT3 LDT4/
MDPVs a

Tailpipe standards: Near-term (year 1) ............................................................................ $78 $70 $125 $245 $258 Long-term (year 6 and beyond) ........................................................ 49 45 97 199 208 Evaporative Standard .............................................................................. 4 4 4 4 4

Notes:

a Weighted average.

We did not receive comments disagreeing with the technology projections or technology cost estimates contained in the proposal. We have, however, revised our cost estimates

somewhat based on new information available since the proposal. We moderately lowered our cost estimates due to adjustments we have made in our technology projections. Based on the results of our vehicle testing program described above in section IV.A.1., we

now believe that a few of the hardware changes we had anticipated are not likely to be needed to meet the standards. Albeit there is always fluctuation, the spot prices of precious

metals have increased somewhat since the proposal and we have adjusted our analysis to reflect those changes.

Overall, the cost estimates are within 5 percent of those in the proposal for LDVs and LLDTs. The changes noted above moderately lowered the costs for HLDTs compared to the proposal. The
cost increase due to the inclusion of
MDPVs offsets most of the lowered costs


### 6776 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

for the LDT4 category. The resulting
cost estimate for the LDT4/MDPVs tailpipe standards is also within 5 percent of the cost estimates for LDT4s contained in the proposal. The detailed technology and cost analyses are
available in the RIA.

We are also finalizing OBD II requirements and onboard vapor recovery (ORVR) requirements for
MDPVs. We have estimated that OBD II will cost about $80, which includes the costs of additional sensors and system improvements. We have estimated ORVR system costs to be about $10. The $10 cost for ORVR does not include any fuel cost savings over the life of the vehicles due the recover of fuel vapor during refueling. ORVR provides a fuel cost savings because the vapors are captured, and burned in the engine, rather than escaping to the atmosphere. We estimate the savings over the life of the vehicle to be about $6. These costs
are not reflected in Table IV.D.–1.

2. Estimated Costs of the Gasoline
Sulfur Standards

As we explained at the beginning of Section IV.C, we expect that most refiners will have to install capital equipment to meet the gasoline sulfur standard. Presuming that refiners will want to minimize the cost involved, the majority of refiners are expected to desulfurize the gasoline blendstock produced by the fluidized catalytic cracker (FCC) unit, although a few may
choose to desulfurize the feed to the
FCC unit. Recent advances have led to significant improvements in the hydrotreating technologies used for FCC gasoline desulfurization. Since these improved technologies represent the lowest cost options and are expected to be used by most refiners needing to install desulfurization equipment, we have based our cost estimates primarily on their use. However, in acknowledgment that some refiners, particularly those which make investment decisions in the near term, are likely to select more traditional approaches using proven technologies, we have included the costs for currently proven desulfurization technologies in our analysis, as well. This is different from the analysis we did in support of our proposal, where we assumed that all refiners would take advantage of the most improved technologies we were
aware of at that time.

For our analysis of the costs of controlling gasoline sulfur, we
estimated the costs in five different regions of the country (Petroleum Administration Districts for Defense, or PADDs) for reductions from the current PADD average gasoline sulfur level down to a 30 ppm average. We then combined the regional costs to develop an average national individual refinery cost, and used this figure to calculate national aggregate capital and operating costs. In our proposal we estimated a single cost for desulfurizing gasoline, using as an assumption for the purpose of analysis that all refiners would upgrade their refineries by 2004 and
that all would choose one of two improved technologies we knew of at
the time. We then reduced this cost over time to reflect expected cost reductions due to further technology advancements and reduced operating costs due to improved understanding of the technologies and refinery debottlenecking. Based on improved information about the availability of technologies, we have now analyzed thecosts of controlling sulfur on a year-byyear basis beginning with 2004, to be consistent with our analysis of the rate at which the industry would invest in desulfurization technologies over the first years of the program and the changing technology selections (andcosts) that would accompany this phasein (discussed in Section IV.C.1 above). A detailed description of our
calculations can be found in the Regulatory Impact Analysis; the reader
can refer to the draft RIA released with the proposed rule for more information on our prior analysis.

We estimate that, on average, refineries which install equipment to meet the 30 ppm average standard will invest about $44 million for capital equipment and spend about $16 million per year for each refinery to cover the operating costs associated with these desulfurization units. Since this average represents many refineries diverse in size and gasoline sulfur level as well as a mix of desulfurization technologies, some refineries will pay more and others less than the average costs. When the average per-refinery cost is aggregated for all the gasoline expected to be produced in this country in 2008 (the first year that all refiners will be required to meet the 30 ppm standard, unless any small refiners are granted a extension of hardship relief), the total
investment for desulfurization processing units (spread between 2003 and 2007) is estimated to be about $4.3 billion, and operating costs for these units is expected to be about $1.3 billion

per year.

Using our estimated capital and operating costs for domestic refineries, we calculated the average per-gallon cost of reducing gasoline sulfur down to 30 ppm for each year as the program is implemented. Using a capital cost amortization factor (based on a seven percent rate of return on investment) and including no taxes, we estimated the average national cost for desulfurizing gasoline to be about 1.7– 1.9 cents per gallon as the program is phased in. This cost is the cost to society of reducing gasoline sulfur down to 30 ppm that we used for estimating
cost effectiveness. Table IV.D.–2 below summarizes our estimates of per-gallon gasoline cost increases for select years.



### TABLE 

### IV.D.–2.—E STIMATED 

### P ER



### G ALLON 

### C OST FOR 

### D ESULFURIZING 

### G ASOLINE IN 

### F UTURE 

### Y EARS

Year Cost (cents/ gallon)

2004 .......................................... 1.9

2005 .......................................... 1.9

2006 .......................................... 1.7

2007 .......................................... 1.7

2008–2018 ................................ 1.7

2019+ ........................................ 1.3

Although the costs shown here are slightly higher than we projected in the proposal, overall, we believe our revised
costs are consistent with those in the proposal and that our improved methodology and information are the
source of the differences. As stated earlier in this section, we believe this analysis more accurately reflects the
actual investment decisions of individual refiners over the years in which the industry is phasing down sulfur levels. Furthermore, we have also made a number of other adjustments to our analysis of capital and operating costs for each individual technology
based on new information received from the technology vendors and information we obtained during the comment period. For example, we now include eight different technologies in our analysis, including some more traditional approaches, whereas in the proposal we only considered two new technologies. Hence, the range of costs is broader. In addition, as explained in the RIA, we now believe we underestimated the capital costs of desulfurization slightly in the proposal
based on our calculation of the costs of providing hydrogen to the processes. We believe our analysis now reflects the most up-to-date information about the costs of installing and operating the various desulfurization technologies included in our analysis. These adjustments are explained in detail in the Regulatory Impact Analysis.

We still believe that over time, particularly in 2006–8 when the last refineries will be making investments, the costs of gasoline desulfurization equipment will be significantly lower


### 6777 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

99 For a sensitivity analysis of our cost estimates using alternative assumptions, please see Chapter V

of the RIA. 100 Figure IV.D.–1 is based on the amortized costs from Tables IV.D.–1 and IV.D.–2. Actual capital investments, particularly important for fuels, would occur prior to and during the initial years of the program, as described above in section IV.D.2. than it is today. Some of the technologies expected to be selected in this time frame (specifically, the new adsorption technologies which we didn’t know about when we proposed these requirements) are projected to cost

about half of what the older technologies cost. Furthermore, with time refiners will have to replace existing desulfurization equipment (as equipment ages), and by then they will
have a number of low cost alternatives to choose from. Thus, as Table IV.D.–2 shows, the long term estimated costs for gasoline desulfurization are lower than those we projected in our proposal. 99

3. What Are the Aggregate Costs of the
Tier 2/Gasoline Sulfur Final Rule?

Using current data for the size and
characteristics of the vehicle fleet and making projections for the future, the per-vehicle and per-gallon fuel costs

described above can be used to estimate

the total cost to the nation for the emission standards in any year. Figure IV.D.–1 portrays the results of these projections. 100

BILLING CODE 6560–50–P

BILLING CODE 6560–50–C

As can be seen from the figure, the annual cost starts out at about $1.9 billion per year and increases over the phase-in period to about $4.1 billion in

2008. Total annualized costs are projected to remain at about $4 billion through 2018. After 2018, annualized fuel costs are projected to decrease

somewhat due to the use of new technologies which would enable refiners to produce low sulfur fuel at a lower cost. The gradual rise in costs long term is due to the effects of projected growth in vehicle sales and fuel consumption. The RIA provides further detail regarding these cost projections. 4. How Does the Cost-effectiveness of This Program Compare to Other Programs?

This section summarizes the costeffectiveness analysis conducted by EPA and its results. The purpose of this analysis is to show that the reductions from the vehicle and fuel controls being finalized today are cost-effective in comparison to alternative means of attaining or maintaining the NAAQS. This analysis involves a comparison of our program not only to past measures, but also to other potential future measures that might be employed to attain and maintain the NAAQS. Both EPA and states have already adopted numerous control measures, and remaining measures tend to be more expensive than those previously employed. As we employ the most costeffective available measures first, more expensive ones tend to become necessary over time.

The emission reductions used to
calculate the cost-effectiveness levels reported here are based on those reductions used for our air quality analysis modeling and benefits analysis. This was done to maintain consistency in the analyses. As noted in Section III.B. above, we have updated our inventory model since the air quality modeling inventories were calculated. In Chapter III of our RIA, Table III.A.– 3 compares the updated Tier 2 model with the air quality analysis modeling
and shows that the emission reductions expected from Tier 2/gasoline sulfur will be substantially greater than the amounts originally calculated. If the


### 6778 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

updated numbers were incorporated
into our cost-effectiveness we would expect the results to be improved over
those shown in this section.

We received a number of comments on our cost-effectiveness analysis in response to our NPRM. Our responses to
these comments can be found in the Response To Comments document.

a. Cost-Effectiveness of This Program

We have calculated the costeffectiveness of the exhaust emission/ gasoline sulfur standards and the evaporative emission standards, based on two different approaches. The first considers the net present value of all
costs incurred and emission reductions generated over the life of an average Tier 2 vehicle. This per-vehicle approach
focuses on the cost-effectiveness of the program from the point of view of the
Tier 2 vehicles which will be used to meet the new requirements, and is the method used in our proposal. However, the per-vehicle approach does not capture all of the costs or emission reductions from the Tier 2/gasoline sulfur program since it does not accountfor the use of low sulfur gasoline in preTier 2 vehicles. Therefore, we have alsocalculated an aggregate costeffectiveness using the net present value
of costs and emission reductions for all in-use vehicles over a 30-year time
frame.

As described earlier in the discussion of the cost of this program, the cost of complying with the new standards will decline over time as manufacturing costs are reduced and amortized capital
investments are recovered. To show theeffect of declining cost in the pervehicle cost-effectiveness analysis, we have developed both near term and long
term cost-effectiveness values. More specifically, these correspond to vehicles sold in years one and six of the vehicle and fuel programs. Vehicle cost is constant from year six onward. Fuel costs per gallon continue to decline slowly in the years past year six; however, the overall impact of this
decline is small and we have decided to use year six results for our long term cost-effectiveness. Chapter VI of the RIA contains a full description of this analysis, and you should look in that
document for more details of the results
summarized here.

The aggregate approach to calculating the cost-effectiveness of our program involves the net present value of all
nationwide emission reductions and costs for a 30-year period beginning with the start of the program in 2004. This timeframe captures both the early period of the program when very few Tier 2 vehicles will be in the fleet, and the later period when essentially all
vehicles in the fleet will meet Tier 2
standards. We have calculated the aggregate cost-effectiveness using the net present value of the nationwide
emission reductions and costs for each calendar year. These emission
reductions and costs are summarized in Sections III.B, III.C, and IV.D.3, and are given for every calendar year in the RIA.
For more information on how the aggregate cost-effectiveness was calculated please refer to the RIA.

Our per-vehicle and aggregate costeffectiveness values are given in Tables
IV.D.–3 and IV.D.–4. Table IV.D.–3 summarizes the per-vehicle, net present value lifetime costs, NMHC+NO Xemission reductions, and resulting costeffectiveness results for our Tier 2/ gasoline sulfur program using sales weighted averages of the costs (both near term and long term) and emission reductions of the various vehicle classes affected. Table IV.D.–4 provides the same information from the program aggregate perspective. It includes the net present value of the 30-year stream of vehicle and fuel costs, NMHC+NO X emission reductions, and the resulting aggregate cost-effectiveness. For simplicity, we have used the midpoint of our estimated range of 20 to 65 percent for the irreversibility effect. The full range of irreversibility would only
cause the cost-effectiveness values to differ from those in Table IV.D–3, for example, by $60/ton to $100/ton. Note that, even though we are setting new standards for PM, those standards are already being met, so there is no cost
associated with the new PM standardand therefore no separate costeffectiveness analysis for PM.

Tables IV.D.–3 and IV.D.–4 also display cost-effectiveness values based on two approaches to account for the
reductions in SO 2 and tailpipe emitted sulfate particulate matter (PM)
associated with the reduction in gasoline sulfur. While these reductions are not central to the program and are therefore not displayed with their own cost-effectiveness, they do represent real emission reductions due to our program.
The first set of cost-effectiveness numbers in the tables simply ignores
these reductions and bases the costeffectiveness on only the NMHC+NO X reductions from Tier 2/gasoline sulfur.
The second set accounts for these ancillary reductions by crediting some of the cost of the program to SO 2 and
PM reduction. The amount of cost
allocated to SO 2 and PM is based on the
cost-effectiveness of SO 2 and PM
emission reductions that could be obtained from alternative, potential future EPA programs.



### TABLE 

### IV.D–3.—P ER

### -V EHICLE 

### C OST

### -E FFECTIVENESS OF THE 

### STANDARDS

Cost basis Discountedlifetime vehicle & fuel

costs Discounted lifetime NMHC + NOX reduction (tons) Discounted lifetimecost-effectiveness per

ton Discounted lifetimecost-effectiveness per

ton with SO 2 and direct PM credit a

Near term cost (production year 1) ................................................................................. $243 0.110 $2, 211 $1,717 Long term cost (production year 6) ................................................................................. 205 0.110 1,863 1,368

Notes:

a $51 credited to SO 2 ($4,800/ton), $4 to direct PM ($10,000/ton).


### 6779 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

101 This rulemaking was remanded by the D.C. Circuit Court on May 14, 1999. However, the analyses completed in support of that rulemaking are still relevant, since they were designed to investigate the cost-effectiveness of a wide variety of potential future emission control strategies.

102 ‘‘Regulatory Impact Analyses for the

Particulate Matter and Ozone National Ambient Air Quality Standards and Proposed Regional Haze Rule,’’ Appendix B, ‘‘Summary of control measures in the PM, regional haze, and ozone partial attainment analyses,’’ Innovative Strategies and Economics Group, Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, NC, July 17, 1997. 

### TABLE 

### IV.D–4.—AGGREGATE 

### C OST

### -E FFECTIVENESS OF THE 

### STANDARDS

Discounted aggregate vehicle & fuel costs Discounted aggregate NMHC + NOX reduction (tons) (millions) Discounted aggregate cost-effectiveness per ton Discounted aggregate cost-effectiveness per ton with SO 2 and direct PM credit a

$48.1 billion 23.5 $2,047 $1,311

Notes:

a $13.8 billion credited to SO 2 ($4,800/ton), $3.5 billion to direct PM ($10,000/ton).

b. How Does the Cost-Effectiveness of This Program Compare With Other Means of Obtaining Mobile Source NOX + NMHC Reductions?

In comparison with other mobile source control programs, we believe thatour program represents the most costeffective new mobile source control strategy currently available that is capable of generating substantial NO X + NMHC reductions. This can be seen by comparing the cost-effectiveness of today’s program with a number of
mobile source standards that EPA has adopted in recent years. Table IV.D.–5
summarizes the cost-effectiveness of
several recent EPA actions.



### TABLE 

### IV.D.–5.—C OST

### -E FFECTIVE



### NESS OF 

### P REVIOUSLY 

### I MPLEMENTED 

### M OBILE 

### S OURCE 

### P ROGRAMS

Program $/ton a NOX+NMHC

2004 Highway HD Diesel

stds .................................... 204–399 Nonroad Diesel engine stds 410–650 Tier 1 vehicle controls .......... 1,980–2,690 NLEV .................................... 1,859 Marine SI engines ................ 1,128–1,778 On-board diagnostics ........... 2,228

Notes: a Costs adjusted to 1997 dollars.

We can see from the table that the cost-effectiveness of the Tier 2/gasoline sulfur standards falls within the range of these other programs. Engine-based standards (the 2004 highway heavy-duty diesel standards, the nonroad dieselengine standards and the marine sparkignited engine standards) have generally been less costly than Tier 2/gasoline sulfur. Vehicle standards, most similar to today’s program, have values comparable to or higher than Tier 2/ gasoline sulfur.

The values in Table IV.D.–5 might imply that further reductions in NOX and VOC from heavy-duty engines
could be more cost-effective than the reductions that will be produced from our Tier 2/gasoline sulfur program. However, we do not believe that to be
the case. While we are indeed developing a proposal for further control from heavy-duty engines, we expect that substantial further emissionreductions will require advanced aftertreatment devices. These devices will be more costly than methods used to meet our past standards, and will have difficulty functioning properly without changes to diesel fuel. We therefore expect that the cost effectiveness of future heavy-duty standards is not likely to be significantly less than the cost effectiveness of today’s rule.

On the light-duty vehicle side, the last
two sets of standards were Tier 1 and NLEV, which had cost-effectiveness comparable to or higher than Tier 2/ gasoline sulfur. Compared to engines, these levels reflect the advanced (and more expensive) state of vehicle control technology, where standards have been in effect for a much longer period than for engines. Considering the increased stringency of the Tier 2 standards, it is noteworthy that the cost-effectiveness of Tier 2/gasoline sulfur is in the same range as these actions. Based on these results, Tier 2/gasoline sulfur is a logical and consistent next step in vehicle
control.

In conclusion, we believe that the Tier2/Gasoline Sulfur program is a costeffective program for mobile source NOX + NMHC control. We are unable to identify another mobile source controlprogram that would be more costeffective than Tier 2/gasoline sulfur while also producing equivalent
reductions in NO X and NMHC
emissions in the same timeframe as our

program.

c. How Does the Cost-Effectiveness of This Program Compare With Other
Known Non-Mobile Source Technologies for Reducing NO X + NMHC?

In evaluating the cost-effectiveness of the Tier 2/Gasoline Sulfur program, we also considered whether our program is cost-effective in comparison with alternative means of attaining or maintaining the NAAQS other than mobile source programs. As described below, we have concluded that Tier 2/
Gasoline Sulfur is cost-effective considering the anticipated cost of other technologies that will be needed to help attain and maintain the NAAQS.

In the context of the Agency’s rulemaking to revise the ozone and PM NAAQS, 101 the Agency compiled a list of additional known technologies that could be considered in devising new emission reductions strategies. 102 Through this broad review, over 50 technologies were identified that could
reduce NO X or VOC. The costeffectiveness of these technologies averaged approximately $5,000/ton for VOC and $13,000/ton for NO X . These values clearly indicate that not only are future emission control strategies likelyto be more expensive (less costeffective) than past strategies, but the
cost-effectiveness of our Tier 2/Gasoline Sulfur program falls at the lower end of the range for potential future strategies.

In addition, our Tier 2/Gasoline Sulfur program will deliver critical further reductions that are not readily obtainable by any other means known to the Agency. If all of the technologies modeled in the NAAQS analysis costing less than $10,000/ton were implemented nationwide, they would produce NO X emission reductions of about 2.9 million tons per year. The Tier 2/Gasoline Sulfur program by itself will generate about 2.8 million tons per year once fully implemented. Given the continuing need for further emission reductions, we believe that Tier 2/Gasoline Sulfur control is clearly a costeffective approach for attaining and maintaining the NAAQS.

We recognize that the costeffectiveness calculated for Tier 2/ Gasoline Sulfur is not strictly comparable to a figure for measures targeted at nonattainment areas, since
Tier 2/Gasoline Sulfur is a nationwide program. However, there are several
additional considerations that have led
us to conclude that Tier 2/Gasoline Sulfur is cost-effective considering


### 6780 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

103 Final Regulatory Impact Analysis: Control ofEmissions of Air Pollution from Highway HeavyDuty Engines, September 16, 1997. 104 The ‘‘section 812 studies’’ refers to (1) US EPA, Report to Congress: The Benefits and Costs of the Clean Air Act, 1970 to 1990, October 1997 (also known as the ‘‘section 812 Retrospective); and (2) the first in the ongoing series of prospective studies estimating the total costs and benefits of the Clean Air Act (see EPA report number: EPA–410–R–99– 001, November 1999). alternative means of attaining and maintaining the NAAQS.

First of all is the fact that the cost
effectiveness of Tier 2/Gasoline Sulfur is
so much better than the numbers developed for the NAAQS analysis. It is only 20 percent as costly per ton as the $10,000 per ton upper limit employed in that analysis for selecting suitable strategies even though, as noted above, Tier 2/Gasoline Sulfur will produce
almost the same level of emission reduction. Furthermore, as a national program, Tier 2/Gasoline Sulfur can be implemented as a single unified rule
without the need for individual action by each of the states.

In dealing with the question of comparing local and national programs, it is also relevant to point out that, because of air transport, the need for

NO X control is a broad regional issue
not confined to non-attainment areas only. To reach attainment, future controls will need to be applied over widespread areas of the country. In the analyses supporting the recent NO X standards for highway diesel engines, 103 we looked at this question in some detail and concluded that the regions expected to impact ozone levels in
ozone nonattainment areas accounted for over 85% of total NOX emissions from a national heavy-duty engine control program. Similarly, NO X emissions in attainment areas also contribute to particulate matter nonattainment problems in downwind areas. Thus, the distinction between local and national control programs for

NO X is less important than it might

appear.

Finally, the statute indicates that in considering the cost-effectiveness of
Tier 2/Gasoline Sulfur EPA should consider not only attainment, but also
maintenance of the standards. Tier 2/
Gasoline Sulfur—unlike nonattainment
area measures—will achieve attainment area reductions that, among other effects, will help to maintain air quality that meets the NAAQS. These reductions relate not only to the ozone and PM NAAQS, but also to SO 2 and

NO 2 , and to CO.

In summary, given the array of
controls that will have to be implemented to make progress toward attaining and maintaining the NAAQS, we believe that the weight of the
evidence from alternative means of providing substantial NO X + NMHC
emission reductions indicates that theTier 2/Gasoline Sulfur program is costeffective. This is true from the perspective of other mobile source control programs or from the perspective of other stationary source technologies that might be considered.

5. Does the Value of the Benefits Outweigh the Cost of the Standards?

While relative cost-effectiveness is the principal economic policy criterion
established for these standards in the Clean Air Act (see CAA § 202(i)), further insight regarding the merits of thestandards can be provided by benefitcost analysis. The purpose of this
section is to summarize the methods we
used and results we obtained in conducting an analysis of the economic benefits of the Tier 2 program, and to compare these economic benefits with
the estimated costs of the rule. In summary, the results of our analysis using the EPAs preferred approach to valuing premature mortality indicate
that the economic benefits of the Tier 2/ gasoline sulfur standards will likely exceed the costs of meeting the standards by about $20 billion (1997$).

a. What Is the Purpose of This BenefitCost Comparison?

Benefit-cost analysis (BCA) is a useful tool for evaluating the economic merits of proposed changes in environmental programs and policies. In its traditional application, BCA estimates the economic ‘‘efficiency’’ of proposed changes in public policy by organizing the various expected consequences and representing those changes in terms of dollars. Expressing the effects of these policy changes in dollar terms provides a common basis for measuring and comparing these various effects. Because improvement in economic efficiency is typically defined to mean maximization of total wealth spread among all members of society, traditional BCA must be supplemented with other analyses in order to gain a full appreciation of the potential merits of new policies and programs. These other analyses may include such things as examinations of legal and institutional constraints and effects; engineering analyses of technology feasibility, performance and cost; or assessment of the air quality need.

In addition to the narrow, economic efficiency focus of most BCAs, the technique is also limited in its ability to project future economic consequences of alternative policies in a definitive way. Critical limitations on the availability, validity, or reliability of data; limitations in the scope and capabilities of environmental and economic effect models; and
controversies and uncertainties surrounding key underlying scientific and economic literature all contribute to an inability to estimate the economic effects of environmental policy changes in exact and unambiguous terms. Under these circumstances, we consider it most appropriate to view BCA as a tool to inform, but not dictate, regulatory
decisions such as the ones reflected in today’s rule.

Despite the limitations inherent in BCA of environmental programs, we
consider it useful to estimate the potential benefits of today’s action both in terms of physical changes in human
health and welfare and environmental change, and in terms of the estimated economic value of those physical changes.

b. What Was Our Overall Approach to the Benefit-Cost Analysis?

The basic question we sought to
answer in the BCA was: ‘‘What are the net yearly economic benefits to society
of the reduction in mobile source emissions likely to be achieved by the final Tier 2 program?’’ In designing an analysis to answer this question, we selected a future year for analysis (2030)that is representative of fullimplementation of the program (i.e., when the U.S. car and light truck population is virtually only Tier 2 vehicles). We also adopted an analytical structure and sequence similar to that
used in the ‘‘section 812 studies’’ 104 to estimate the total benefits and costs of the entire Clean Air Act. Moreover, we used many of the same models, and assumptions actually used in the section 812 studies, and other Regulatory Impact Analyses (RIA’s) prepared by the Office of Air and Radiation. By adopting the major design elements, models, and assumptions developed for the section 812 studies and other RIA’s, we have largely relied on methods which have already received extensive review by the independent Science Advisory Board, by the public, and by other federal agencies.

c. What Are the Significant Limitations of the Benefit-Cost Analysis?

Every BCA examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, limitations in model capabilities (such as geographic coverage), and uncertainties in the underlying scientific and economic


### 6781 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

105 Full documentation of the SAB

recommendations can be found at their website ( www.epa.gov/sab) under the following references: EPA–SAB–COUNCIL–ADV–98–003, 1998; EPA– SAB–COUNCIL–ADV–99–05, 1999; EPA–SAB– COUNCIL–ADV–99–012, 1999; EPA–SAB– COUNCIL–ADV–00–001, 1999; and EPA–SAB–
COUNCIL–ADV–00–002, 1999. studies used to configure the benefit and
cost models. Deficiencies in the
scientific literature often result in the inability to estimate changes in health and environmental effects, such as potential increases in premature mortality associated with increased exposure to carbon monoxide.
Deficiencies in the economics literature often result in the inability to assign
economic values even to those health
and environmental outcomes which can be quantified, such as changes in visibility in residential areas. While these general uncertainties in the underlying scientific and economics
literatures are discussed in detail in the RIA and its supporting documents and references, the key uncertainties which have a bearing on the results of the BCA of today’s action are:

• The exclusion of potentially significant benefit categories ( e.g., health and ecological benefits of incidentally controlled hazardous air pollutants),

• Errors in measurement and projection for variables such as population growth,

• Variability in the estimated relationships of health and welfare effects to changes in pollutant

concentrations.

In addition to these uncertainties and shortcomings which pervade all analyses of criteria air pollutant control programs, a number of limitations apply specifically to the BCA of today’s action. Though we used the best data and models currently available, we were required to adopt a number of simplifying assumptions and to use data sets which, while reasonably close, did not match precisely the conditions and effects expected to result from implementation of the standards. For example, to estimate the effects of the program at full implementation we projected vehicle miles traveled and populations in the year 2030. These assumptions may play a significant role in determining the magnitude of the benefits estimate. In addition, although
the emissions data sets used for this analysis have been updated from those used in the proposal, they may not anticipate the emissions reductions realized by other future actions and by expected near-future control programs. For example, it is possible that the Tier 2/gasoline sulfur standards will not be the governing vehicle emissions standards in 2030. In the years before 2030, the benefits from the Tier 2 program will be less than those estimated here (significantly less in the early years), because the Tier 2 fleet will not be fully phased in. Finally, the implementation period for phasing-in the rule requirements is a critical period that deserves careful evaluation. The benefit-cost analysis for 2030 is not significantly affected by alternative phase-in decisions, the primary impact of which will occur in the 2005–2015 time frame. As a result, the analysis of phase-in alternatives must rely on other types of analysis ( e.g., cost-effectiveness analysis).

The key limitations and uncertainties unique to the BCA of the final rule, therefore, include:

• Uncertainties in the estimation of future year emissions inventories and air quality,

• Uncertainties associated with the extrapolation of air quality monitoring
data to some unmonitored areas required to better capture the effects of the standards on affected populations,
and

• Uncertainties associated with the effect of potential future actions to limit

emissions.

Despite these uncertainties, which are
discussed in more detail or referenced in the RIA, we believe the BCA provide a reasonable indication of the expected economic benefits of the Tier 2 program in 2030 under one set of assumptions. This is because the analysis focuses on estimating the economic effects of the changes in air quality conditions expected to result from today’s action, rather than focusing on developing a precise prediction of the absolute levels of air quality likely to prevail in 2030. An analysis focusing on the changes in air quality can give useful insights into the likely economic effects of emission reductions of the magnitude expected to result from today’s rule.

d. How Has the Benefit-Cost Analysis Changed From Proposal?

We significantly improved the analysis that was presented at proposal. For the final rule, EPA updated the emissions inventory from 1990 to 1996 using updated models, refined the projections of the effects of the rule when it is fully implemented, and updated our air quality modeling to reflect new programs issued since 1990. In addition, we also updated our assumptions for estimating physical effects and monetary benefits based on
recommendations from the EPA’s Science Advisory Board (SAB) during
the summer of 1999. Details on these
recommendations can be found in the advisory statements published by the

SAB. 105 All of the changes made since the analysis at proposal serve to update and improve the analysis.

e. How Did We Perform the Benefit-Cost Analysis?

The analytical sequence begins with a projection of the mix of technologies likely to be deployed to comply with the new standards, and the costs incurred and emissions reductions achieved by these changes in technology. The Tier 2 program has various cost and emission related components, as described earlier in this section. These components would begin at various times and in some cases would phase in over time. This means that during the early years of the program there would not be a
consistent match between cost and benefits. This is especially true for the vehicle control portions of the program,
where the full vehicle cost would be incurred at the time of vehicle purchase, while the fuel cost along with the
emission reductions and benefits would occur throughout the lifetime of the
vehicle.

To develop a benefit-cost number that is representative of a fleet of Tier 2 vehicles, we need to have a stable set of
cost and emission reductions to use. This means using a future year where the fleet is fully turned over and there
is a consistent annual cost and annual
emission reduction. For the Tier 2 program, this stability would not occur
until well into the future. For this analysis, we selected the year 2030. The resulting analysis represents a snapshot of benefits and costs in a future year in which the light-duty fleet consists almost entirely of Tier 2 vehicles. As such, it depicts the maximum emission reductions (and resultant benefits) and among the lowest costs that would be achieved in any one year by the program on a ‘‘per mile’’ basis. (Note, however, that net benefits would continue to grow over time beyond those resulting from this analysis, because of growth in population and vehicle miles traveled.) Thus, based on the long-term costs for a fully turned over fleet, the resulting
benefit-cost ratio will be close to its maximum point (for those benefits which we have been able to value).

To present a BCA, we designed the
cost estimate to reflect conditions in the same year as the benefit valuation. Costs are, therefore, developed for the year 2030 fleet. For this purpose we used the long term cost once the capital costs
have been recovered and the manufacturing learning curve


### 6782 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

106 Though California is included based on the expectation that reductions in surrounding states will achieve some benefits in California, this analysis does not assume additional reductions in California emissions beyond those already achieved by prevailing standards. reductions have been realized, since this
will be the case in 2030.

We also made adjustments in the
costs to account for the fact that there
is a time difference between when some of the costs are expended and when the
benefits are realized. The vehicle costs are expended when the vehicle is sold,
while the fuel related costs and the
benefits are distributed over the life of
the vehicle. We resolved this difference by using costs distributed over time such that there is a constant cost per ton
of emissions reduction and such that the net present value of these distributed costs corresponds to the net present
value of the actual costs.

The resulting adjusted costs are somewhat greater than the expected actual annual cost of the program, reflecting the time value adjustment. Thus, the costs presented in this section do not represent expected actual annual costs for 2030. Rather, they represent an approximation of the steady-state cost per ton that would likely prevail in that time period. The benefit cost ratio for the earlier years of the program would be expected to be lower than that based on these costs, since the per-vehicle costs are larger in the early years of the program while the benefits are smaller.

In order to estimate the changes in air quality conditions which would result from these emissions reductions, we developed two separate, year 2030
emissions inventories to be used as inputs to the air quality models. The first, baseline inventory, reflects the bestavailable approximation of the countyby-county emissions for NO X , VOC, and

SO 2 expected to prevail in the year 2030
in the absence of the standards. To generate the second, control case inventory, we first estimated the change in vehicle emissions, by pollutant and by county, expected to be achieved by
the 2030 control scenario described
above. We then took the baseline emissions inventory and subtracted theestimated reduction for each countypollutant combination to generate the second, control case emissions inventory. Taken together, the two resulting emissions inventories reflect
two alternative states of the world and the differences between them represent
our best estimate of the reductions in
emissions which would result from our
control scenario.

With these two emissions inventories in hand, the next step was to ‘‘map’’ thecounty-by-county and pollutant-bypollutant emission estimates to the input grid cells of two air quality models and one deposition model. The first model, called the Urban Airshed Model (UAM), is designed to estimate the tropospheric ozone concentrations resulting from a specific inventory of emissions of ozone precursor pollutants, particularly NO X and NMHC. The second model, called the ClimatologicalRegional Dispersion Model SourceReceptor Matrix model (S–R Matrix), is designed to estimate the changes in ambient particulate matter and visibility which would result from a specific set of changes in emissions of primary particulate matter and secondary particulate matter precursors, such as

SO 2 , NO X , and NMHC. Also, nitrogen loadings to watersheds were estimated using factors derived from previous modeling from the Regional Acid Deposition Model (RADM). By running
both the baseline and control case emissions inventories through these models, we were able to estimate the expected 2030 air quality conditions and the changes in air quality
conditions which would result from the emissions reductions expected to be achieved by the Tier 2 program.

After developing these two sets of year 2030 air quality profiles, we used
the same health and environmental
effect models used in the section 812
studies to calculate the differences in
human health and environmental outcomes projected to occur with and without the proposed standards. Specifically, we used the Criteria Air Pollutant Modeling System (CAPMS) to estimate changes in human health outcomes, and the Agricultural Simulation Model (AGSIM) to estimate changes in yields of a selected few agricultural crops. In addition, the impacts of reduced visibility impairment and estimates of the effect of changes in nitrogen deposition to a
selection of sensitive estuaries were estimated using slightly modified
versions of the methods used in thesection 812 studies. Several air qualityrelated health and environmental benefits, however, could not be calculated for the BCA of today’s proposed standards. Changes in human
health and environmental effects due to changes in ambient concentrations of carbon monoxide (CO), gaseous sulfur dioxide (SO 2), gaseous nitrogen dioxide (NO 2), and hazardous air pollutants could not be included. In addition,
some health and environmental benefits from changes in ozone and PM could not be included in our analysis (i.e., commercial forestry benefits).

To characterize the total economic
value of the reductions in adverse
effects achieved across the lower 48

states, 106 we used the same set of economic valuation coefficients and models used in the section 812 studies, as approved by the SAB. The net monetary benefits of the Tier 2 program were then calculated by subtracting the estimated costs of compliance from the estimated monetary benefits of the
reductions in adverse health and
environmental effects.

The last step of the analysis is to characterize the uncertainty surrounding our estimate of benefits. Again, we follow the recommendations of the SAB for the presentation of uncertainty. They recommend that a primary estimate should be presented along with a description of the uncertainty associated with each endpoint. At proposal, our characterization of uncertainty was based on an estimated range of benefits which might occur if important but uncertain underlying factors were allowed to vary. This approach, however, is criticized by the SAB because while the low- or high-end estimates provided for individual endpoints was ‘‘plausible,’’ the probability of all of the assumptions in these estimates occurring simultaneously was likely to be small.

Therefore, for the final Tier 2/gasoline sulfur rule, the benefit analysis adopts an approach similar to the section 812 study. Our analysis first presents our estimate for a primary set of benefit endpoints followed by a presentation of ‘‘alternative calculations’’ of key health and welfare endpoints to characterize the uncertainty in this primary set. However, the adoption of a value for the projected reduction in the risk of premature mortality is the subject of continuing discussion within the economic and public policy analysis community within and outside the Administration. In response to the sensitivity on this issue, we provide estimates reflecting two alternative approaches for mortality benefits: the EPAs preferred approach using the value of a statistical life, and an alternative approach using the value of a statistical life years. These are
discussed further in section f. of this presentation. The presentation of the
alternative calculations for certain endpoints seeks to demonstrate how much the overall benefit estimate might vary based on the value EPA has given to a parameter (which has some uncertainty associated with it) underlying the estimates for human
health and environmental effect
incidence and the economic valuation


### 6783 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

of those effects. These alternative calculations represent conditions that are possible to occur, however, EPA has selected the best supported values based
on current scientific literature for use in the primary estimate. The alternate
calculations include:

• Presentation of an estimated confidence interval around the Primary
estimate of benefits to characterize The
standard error in the C-R and valuation studies used in developing benefit estimates for each endpoint;

• Valuing PM-related premature mortality based on a different C-R study;

• Value of avoided premature mortality incidences based on statistical life years;

• Consideration of reversals in
chronic bronchitis treated as lowest severity cases;

• Value of visibility changes in all Class I areas;

• Value of visibility changes in Eastern U.S. residential areas;

• Value of visibility changes in Western U.S. residential areas;

• Value of reduced household soiling damage; and

• Avoided costs of reducing nitrogen loadings in east coast estuaries.

For instance, the study by Dockery, et al. estimates of the relationship between PM exposure and premature mortality is a plausible alternative to the Pope, et al. study used for the Primary estimate of
benefits. The SAB has noted that ‘‘the study had better monitoring with less
measurement error than did most other studies’’ (EPA–SAB–COUNCIL–ADV– 99–012, 1999). The Dockery study had a more limited geographic scope (and a smaller study population) than the Pope, et al. study and the Pope study appears more likely to mitigate a key source of potential confounding. The Dockery study also covered a broader age category (25 and older compared to 30 and older in the Pope study) and followed the cohort for a longer period (15 years compared to 8 years in the Pope study). For these reasons, the Dockery study is considered to be a plausible alternative estimate of the avoided premature mortality incidences associated with the final Tier 2/gasoline
sulfur rule. The alternative estimate for mortality can be substituted for the valuation component in our primary estimate of mortality benefits to observe how the net benefits of the program may be influenced by this assumption. Unfortunately, it is not possible to combine all of the assumptions used in
the alternate calculations to arrive at different total benefit estimates because, it is highly unlikely that the selected
combination of alternative values would all occur simultaneously. Therefore, it is better to consider each alternative calculation individually to assess the uncertainty in the estimate.

In addition to the estimate for the primary set of endpoints and alternative calculations of benefits, our RIA also presents an appendix with supplemental benefit estimates and sensitivity analyses of other key parameters in the benefit analysis that have greater uncertainty surrounding
them due to limitations in the scientific literature. Supplemental estimates are presented for premature mortality associated with short-term exposures to PM and ozone, asthma attacks,
occurrences of moderate or worse asthma symptoms, and an estimate of the avoided incidences of premature mortality in infants.

Even with our efforts to fully disclose the uncertainty in our estimate, this uncertainty presentation method does not provide a definitive or complete picture of the true range of monetized benefits estimates. This approach, as implemented in this BCA, does not reflect important uncertainties in earlier steps of the analysis, including estimation of compliance technologies and strategies, emissions reductions and costs associated with those technologies and strategies, and air quality and deposition changes achieved by those
emissions reductions. Nor does this approach provide a full accounting of all potential benefits associated with the Tier 2/gasoline sulfur standards, due to data or methodological limitations. Therefore, the uncertainty range is only representative of those benefits that we were able to quantify and monetize.

f. What Were the Results of the BenefitCost Analysis?

The BCA for the Tier 2 program reflects a single year ‘‘snapshot’’ of the yearly benefits and costs expected to be
realized once the standards have been fully implemented and non-compliant
vehicles have all been retired. Near-term costs will be higher than long-run costs
as vehicle manufacturers and oil companies invest in new capital equipment and develop and implement new technologies. In addition, near-term benefits will be lower than long-run
benefits because it will take a number of years for Tier 2-compliant vehicles to fully displace older, more polluting vehicles. However, as described earlier, we have adjusted the cost estimates upward to compensate for some of this discrepancy in the timing of benefitsand costs and to ensure that the longterm benefits and costs are calculated on a consistent basis. The resulting adjusted long-term cost value is given in
Table IV.D.–5a. Because of the adjustment process, the cost estimates should not be interpreted as reflecting the actual costs expected to be incurred in the year 2030. Actual program costs
can be found in Section IV.D.3.



### TABLE 

### IV.D.–5A 

### .—A DJUSTED 

### C OST OF

THE 

### T IER 

### 2/G ASOLINE 

### S ULFUR 

### R ULE

FOR 

### C OMPARISON TO 

### B ENEFITS

Cost basis Adjusted

cost (billions of

dollars)

Long term a ............................... 5.3

Notes:

a Note that this estimate of cost is only for purposes of comparing with our 2030 benefits estimate. See Figure IV.D.–1 for our portrayal of total annualized cost of the rule.

With respect to the benefits, several
different measures of benefits can be useful to compare and contrast to the estimated compliance costs. These benefit measures include (a) the tons of emissions reductions achieved, (b) the
reductions in incidences of adverse health and environmental effects, and (c) the estimated economic value of
those reduced adverse effects. Calculating the cost per ton of pollutant reduced is particularly useful for comparing the cost-effectiveness of the new standards or programs against existing programs or alternative new programs achieving reductions in the same pollutant or combination of pollutants. The cost-effectiveness analysis presented earlier in this preamble provides such calculations on a per-vehicle basis. Considering the
absolute numbers of avoided adverse
health and environmental effects can also provide valuable insights into the
nature of the health and environmental problem being addressed by the rule as well as the magnitude of the total public health and environmental gains potentially achieved by the rule. Finally, when considered along with other important economic dimensions —including environmental justice, small business financial effects, and
other outcomes related to the distribution of benefits and costs among particular groups— the direct comparison of quantified economic benefits and economic costs can provide useful insights into the potential magnitude of the estimated net economic effect of the rule, keeping in
mind the limited set of effects we are
able to monetize.

Table IV.D.–6 presents the EPAs preferred approach to estimate the
benefits of both the estimated
reductions in adverse effect incidences
and the estimated economic value of


### 6784 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

107 Specifically, the VSLY estimate is calculated by amortizing the $5.9 million mean VSL estimate over the 35 years of life expectancy associated with subjects in the labor market studies. The resulting estimate, using a 5 percent discount rate, is $360,000 per life-year saved in 1997 dollars. This annual average value of a life-year is then multiplied times the number of years of remaining life expectancy for the affected population (in the case of PM-related premature mortality, the average number of $ life-years saved is 14. those incidence reductions. Specifically,
the table lists the avoided incidences of
individual health and environmental effects, the pollutant associated with each of these endpoints, and the
estimated economic value of those avoided incidences. For several effects, particularly environmental effects,
direct calculation of economic value in response to air quality conditions is performed, eliminating the intermediate step of calculating incidences. As the table indicates, we estimate that the Tier 2 program will produce 2300 fewer cases of chronic bronchitis, and we also see significant improvements in minor restricted activity days (with an estimated 6,255,500 fewer cases). Our estimate also incorporates significant reductions in impacts on children’s health, showing reductions of 7,900 cases of acute bronchitis, 87,200 fewer cases of lower respiratory symptoms, and 86,600 fewer cases of upper respiratory symptoms in asthmatic
children.

Total monetized benefits, however, are driven primarily by the estimated 4300 fewer premature fatalities. The adoption of a value for the projected reduction in the risk of premature mortality is the subject of continuing
discussion within the economic and public policy analysis community
within and outside the Administration. In response to the sensitivity on this issue, we provide estimates reflecting two alternative approaches. The first approach—supported by some in the above community and preferred by
EPA—uses a Value of a Statistical Life (VSL) approach developed for the Clean
Air Act Section 812 benefit-cost studies. This VSL estimate of $5.9 million (1997$) was derived from a set of 26 studies identified by EPA using criteria established in Viscusi (1992), as those most appropriate for environmental policy analysis applications.

An alternative, age-adjusted approach is preferred by some others in the above community both within and outside the Administration. This approach was also developed for the Section 812 studies and addresses concerns with applying the VSL estimate—reflecting a valuation derived mostly from labor market studies involving healthy working-age
manual laborers—to PM-related mortality risks that are primarily associated with older populations and those with impaired health status. This alternative approach leads to an
estimate of the value of a statistical life year (VSLY), which is derived directly from the VSL estimate. It differs only in incorporating an explicit assumption about the number of life years saved and an implicit assumption that the valuation of each life year is not affected by age. 107 The mean VSLY is $360,000 (1997$); combining this number with a mean life expectancy of 14 years yields an age-adjusted VSL of $3.6 million (1997$).

Both approaches are imperfect, and raise difficult methodological issues which are discussed in depth in the recently published Section 812 Prospective Study, the draft EPAEconomic Guidelines, and the peerreview commentaries prepared in support of each of these documents. For example, both methodologies embed assumptions (explicit or implicit) about
which there is little or no definitive scientific guidance. In particular, both methods adopt the assumption that the risk versus dollars trade-offs revealed by
available labor market studies are applicable to the risk versus dollar trade-offs in an air pollution context.

EPA currently prefers the VSL approach because, essentially, the method reflects the direct, application
of what EPA considers to be the most
reliable estimates for valuation of premature mortality available in the
current economic literature. While there
are several differences between the labor
market studies EPA uses to derive a VSL estimate and the particulate matter air pollution context addressed here, those differences in the affected populations and the nature of the risks imply both upward and downward adjustments. For example, adjusting for age differences may imply the need to adjust the $5.9 million VSL downward as would adjusting for health differences, but the involuntary nature of air pollution-related risks and the
lower level of risk-aversion of the
manual laborers in the labor market studies may imply the need for upward adjustments. In the absence of a comprehensive and balanced set of adjustment factors, EPA believes it is reasonable to continue to use the $5.9 million value while acknowledging the significant limitations and uncertainties in the available literature. Furthermore, EPA prefers not to draw distinctions in the monetary value assigned to the lives saved even if they differ in age, health status, socioeconomic status, gender or
other characteristic of the adult population. Those who favor the alternative, ageadjusted approach (i.e. the VSLY approach) emphasize that the value of a statistical life is not a single number relevant for all situations. Indeed, the VSL estimate of $5.9 million (1997 dollars) is itself the central tendency of
a number of estimates of the VSL for some rather narrowly defined populations. When there are significant differences between the population affected by a particular health risk and the populations used in the labor market studies—as is the case here—they prefer to adjust the VSL estimate to reflect those differences. While acknowledging that the VSLY approach provides an admittedly crude adjustment (for age though not for other possible differences between the populations), they point out that it has the advantage of yielding an estimate that is not presumptively biased. Proponents of adjusting for age differences using the VSLY approach fully concur that enormous uncertainty
remains on both sides of this estimate— upwards as well as downwards—and that the populations differ in ways other than age (and therefore life expectancy). But rather than waiting for all relevant questions to be answered, they prefer a process of refining estimates by incorporating new information and
evidence as it becomes available.

In addition to the presentation of mortality valuation, this table also
indicates with a ‘‘B’’ those additional
health and environmental benefits which could not be expressed in quantitative incidence and/or economic value terms. A full listing of the benefit categories that could not be quantified
or monetized in our estimate are provided in Table IV.D.–8. For instance, visibility is expected to improve in all areas of the country, with the largest improvements occurring in heavily populated residential areas ( e.g., 21% of the metropolitan areas show an improvement of 0.5 deciviews or more). However, due to limitations on sources to value these effects, we include a ‘‘B’’ in the primary estimate table for this category. Likewise, the Tier 2/gasoline sulfur rule will also provide progress for some estuaries to meet their goals for reducing nitrogen deposition ( e.g., nitrogen loadings for the Albemarle/ Pamlico Sound are reduced by 27% of their reductions goal), however, this endpoint is also displayed with a ‘‘B’’ in the table. A full appreciation of the overall economic consequences of the Tier 2/gasoline sulfur standards requires
consideration of all benefits and costs expected to result from the new standards, not just those benefits and


### 6785 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

costs which could be expressed here in
dollar terms.

In summary, the VSL approach—the approach EPA prefers—yields a monetized benefit estimate of $25.2billion in 2030. The alternative, ageadjusted VSLY approach (presented in Table IV.D.7) yields monetary benefits of approximately $13.8 billion in 2030.



### TABLE 

### IV.D.–6.—EPA P REFERRED 

### E STIMATE OF THE 

### A NNUAL 

### Q UANTIFIED AND 

### M ONETIZED 

### B ENEFITS 

### ASSOCIATED 

### W ITH 

### I MPROVED 

### A IR 

### Q UALITY 

### R ESULTING 

### F ROM THE 

### T IER 

### 2/G ASOLINE 

### S ULFUR 

### R ULE IN 

### 2030

Endpoint Pollutant Avoided incidence c (cases/year) Monetary benefits d (millions 1997$)

Premature mortality a, b (adults, 30 and over) .............................................. PM b ....................................... 4,300 ................ $23,380 Chronic asthma (adult males, 27 and over) ................................................ Ozone ................................. .. 400 ................... 10
Chronic bronchitis ........................................................................................ PM ................... ...................... 2,300 ................ 730 Hospital Admissions from Respiratory Causes ........................................... Ozone and PM ...................... 2,200 .. .............. 20 Hospital Admissions from Cardiovascular Causes ...................................... Ozone and PM ...................... 800 ...... ............. 10 Emergency Room Visits for Asthma ............................................................ Ozone and PM ...................... 1 ,200 ................ <1 Acute bronchitis (children, 8–12) ................................................................. PM ........................... .............. 7,900 ................ <1 Lower respiratory symptoms (LRS) (children, 7–14) ................................... PM ......................................... 87,100 .............. <5 Upper respiratory symptoms (URS) (asthmatic children, 9–11) .................. PM ......................................... 86,500 . ............. <5 Shortness of breath (African American asthmatics, 7–12) .......................... PM ......................................... 17, 400 .............. <1 Work loss days (WLD) (adults, 18–65) ........................................................ PM ................................. ........ 682,900 ............ 70 Minor restricted activity days (MRAD)/Acute respiratory symptoms ........... Ozone and PM ...................... 5,855,000 ......... 270
Other health effects c .................................................................................... Ozone, PM, CO, HAPS ........ U 1 +U 2+U 3 +U 4 ... B 1 +B 2+B 3 +B4 Decreased worker productivity ..................................................................... Ozone ........................ ........... ........................... 140 Recreational visibility (86 Class I Areas) ..................................................... PM .............................. ........... ........................... 370 Residential visibility ...................................................................................... PM ................. ........................ ........................... B 5 Household soiling damage ........................................................................... PM .......................... ............... ........................... B 6 Materials damage ......................................................................................... PM .................... ..................... ........................... B7 Nitrogen Deposition to Estuaries ................................................................. Nitrogen ...................... .......... ........................... B 8 Agricultural crop damage (6 crops) ............................................................. Ozone ........................... ........ ........................... 220 Commercial forest damage .......................................................................... Ozone ........................ ........... ........................... B 9 Other welfare effects e .................................................................................. Ozone, PM, CO, HAPS ........ .................. ......... B 10+B 11 +B 12+B 13 Monetized Total f, g

............................................................................ ............................................... .... ....................... $25,220+B

Notes:

a Premature mortality associated with ozone is not separately included in this analysis. It is assumed that the Pope, et al. C–R function for premature mortality captures both PM mortality benefits and any mortality benefits associated with other air pollutants. Also notethat the valuation assumes the 5 year distributed lag structure described earlier.

b PM reductions are due to reductions in NOX and SO 2 resulting from the Tier 2/Gasoline Sulfur rule.

c Incidences are rounded to the nearest 100.

d Dollar values are rounded to the nearest 10 million.

e The Ui are the incidences and the Bi are the values for the unquantified category i. A detailed listing of unquantified PM, ozo ne, CO, and HAPS related health and welfare effects is provided in Table IV.D.–8.

f B is equal to the sum of all unmonetized categories, i.e. B 1 +B 2+ * * * +B 13

. g These estimates are based on the EPA preferred approach for valuing reductions in premature mortality, the VSL approach. This a pproach and an alternative, age-adjusted approach—the VSLY approach—are discussed more fully in section f above.



### TABLE 

### IV.D.–7.—T IER 

### 2/G ASOLINE 

### S ULFUR 

### R ULE 

### : 2030 M ONETIZED 

### B ENEFITS 

### E STIMATES FOR 

### A LTERNATIVE 

### P REMATURE 

### M ORTALITY 

### VALUATION 

### A PPROACHES

[Millions of 1997 dollars]

Premature mortality valuation approach PM mortality benefits Total benefits

Value of statistical life (VSL) ($5.9 million per life saved)

a ....................................................................................... $23,380 $25,220 + B Value of statistical life-years (VSLY) ($360,000 per life-year saved, which implies $3.6 million per life saved,

based on the mean of 14 life years saved) a,b

. 11,900 13,790 + B

Notes:

a Premature mortality estimates are determined assuming a 5 year distributed lag, which applies 25 percent of the incidence in year 1 and 2, and then 16.7 percent of the incidence in years 3, 4, and 5.

b The VSLY estimate is calculated by amortizing the $5.9 million mean VSL estimate over the 35 years of life expectancy associated with subjects in the labor market studies used to obtain the VSL estimate. The resulting estimate, using a 5 percent discount rate, is $360,000 per lifeyear saved in 1997 dollars. This approach is discussed more fully in section f above.


### 6786 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

TABLE 

### IV.D.–8.—A DDITIONAL 

### , N ON



### - MONETIZED 

### B ENEFITS OF THE 

### T IER 

### 2/G ASOLINE 

### S ULFUR 

### STANDARDS

Pollutant Unquantified effects

Ozone Health ......................................................... Premature mortality. a Increased airway responsiveness to stimuli. Inflammation in the lung Chronic respiratory damage Premature aging of the lungs Acute inflammation and respiratory cell damage Increased susceptibility to respiratory infection Non-asthma respiratory emergency room visits Reductions in screening of UV–b radiation Ozone Welfare ....................................................... Decreased yields for commercial forests Decreased yields for fruits and vegetables Decreased yields for non-commercial crops Damage to urban ornamental plants Impacts on recreational demand from damaged forest aesthetics Damage to ecosystem functions PM Health .............................................................. Infant mortality Low birth weight Changes in pulmonary function Chronic respiratory diseases other than chronic bronchitis Morphological changes
Altered host defense mechanisms Nitrogen and Sulfate Deposition Welfare .............. Impacts of acidic sulfate and nitrate deposition on commercial forests Impacts of acidic deposition to commercial freshwater fishing Impacts of acidic deposition to recreation in terrestrial ecosystems Reduced existence values for currently healthy ecosystems Impacts of nitrogen deposition on commercial fishing, agriculture, and forests Impacts of nitrogen deposition on recreation in estuarine ecosystems CO Health .............................................................. Premature mortality a Behavioral effects Hospital admissions—respiratory, cardiovascular, and other
Other cardiovascular effects Developmental effects Decreased time to onset of angina Non-asthma respiratory ER visits HAPS Health .......................................................... Cancer (benzene, 1,3-butadiene, formaldehyde, acetaldehyde) Anemia (benzene) Disruption of production of blood components (benzene) Reduction in the number of blood platelets (benzene) Excessive bone marrow formation (benzene) Depression of lymphocyte counts (benzene) Reproductive and developmental effects (1,3-butadiene) Irritation of eyes and mucus membranes (formaldehyde) Respiratory irritation (formaldehyde) Asthma attacks in asthmatics (formaldehyde) Asthma-like symptoms in non-asthmatics (formaldehyde) Irritation of the eyes, skin, and respiratory tract (acetaldehyde)
HAPS Welfare ........................................................ Direct toxic effects to animals

Bioaccumlation in the food chain

a Premature mortality associated with ozone and carbon monoxide is not separately included in this analysis. It is assumed that t he Pope, et al. C–R function for premature mortality captures both PM mortality benefits and any mortality benefits associated with other air pollutants.

In addition, in analyzing the present rule, we recognized that the benefits estimates were subject to a number of uncertainties with other parameters. In Table IV D–9, we present alternative calculations representing the effect of different assumptions on individual elements of the benefits analysis and on the total benefits estimate. For example,
this table can be used to answer questions like ‘‘What would total benefits be if we were to use the Dockery, et al. C–R function to estimate avoided premature mortality?’’ This table also displays some assumptions
that can be made to value some of the categories that are indicated with a ‘‘B’’ in the primary estimate. Overall, this table provides alternative calculations both for valuation issues (e.g., the correct value for a statistical life saved) and for physical effects issues (e.g., how reversals in chronic illnesses are treated). We show how the alternative assumption being valued would change the resulting total primary estimate, and the percentage change from the primary
estimate associated with the alternative
calculation. This table is not meant to be comprehensive. Rather, it reflects some of the key issues identified by EPA or commenters as likely to have a significant impact on total benefits.


### 6787 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

108 Generally the provisions of this section V that apply to HLDTs also apply to MDPVs. See section IV.B.4.g for a thorough discussion of the main program elements and how they impact MDPVs. 

### TABLE 

### IV.D.–9.—A LTERNATIVE 

### B ENEFITS 

### CALCULATIONS FOR THE 

### T IER 

### 2 G ASOLINE 

### S ULFUR 

### R ULE IN 

### 2030

Alternative calculation Impact on primary benefit
estimate (million 1997$)

5th percentile of ‘‘measurement’’ uncertainty distribution .....................................................................

..................... ¥ $20,300 (

¥ 81%) 95th percentile of ‘‘measurement’’ uncertainty distribution .................................................................... .................... +33,900 (+134%) PM-related premature mortality based on Dockery et al. ......................................................................... ................. +30,200 (+120%) Value of avoided premature mortality incidences based on statistical life years. ...............................................

...... ¥ 11,500 (

¥ 46%) Reversals in chronic bronchitis treated as lowest severity cases ............................................................... .............. +280 (+1%) Value of visibility changes in all class I areas ............................................................................... ............................ +180 (+1%) Value of visibility changes in eastern U.S. residential areas .................................................................. ................... +420 (+2%) Value of visibility changes in western U.S. residential areas .................................................................. .................. +130 (+1%) Household soiling damage ....................................................................................................... .................................. +110 (+1%) Avoided costs of reducing nitrogen loadings in east coast estuaries ............................................................ ........... +160 (+1%)

The estimated adjusted cost of implementing the final Tier 2 program is $5.3 billion (1997$), while the estimate of monetized benefits using EPA’s preferred approach for monetizing reductions in PM-related premature mortality—the VSL approach—are $25.2 billion (1997$). Monetized net benefits using EPA’s preferred method for valuing avoided incidences of premature mortality are approximately $19.9 billion (1997$). Using the alternative, age-adjusted approach—the VSLY approach—total monetized benefits are projected to be around $13.8 billion (1997$). Monetized net benefits using this approach are approximately $8.5 billion (1997$). Therefore, implementation of the Tier 2 program will provide society with a net gain in social welfare. Tables VI.D.–10a and IV.D.–10b summarize the costs, benefits, and net benefits for the two alternative valuation approaches.



### TABLE 

### IV.D.–10A 

### .—2030 A NNUAL 

### M ONETIZED 

### C OSTS 

### , B ENEFITS



### , AND 

### N ET 

### B ENEFITS FOR THE 

### F INAL 

### T IER 

### 2/G ASOLINE 

### S ULFUR 

### R ULE 

### : EPA

P REFERRED 

### E STIMATE 

### U SING THE 

### VALUE OF 

### STATISTICAL 

### L IVES 

### SAVED 

### A PPROACH TO 

### VALUE 

### R EDUCTIONS 

### I N 

### P REMATURE 

### M ORTALITY a

Billion 1997

(dollars)

Adjusted compliance costs ..... $5.3

Monetized PM-related benefits b

. 24.7+BPM

Monetized Ozone-related benefitsb

. 0.5+B Ozone

Monetized net benefits c,d ........ 19.9+B

Notes:

a For this section , all costs and benefits arerounded to the nearest 100 million. Thus, figures presented in this chapter may not exactly equal benefit and cost numbers presented in earlier sections of the chapter. b Not all possible benefits or disbenefits arequantified and monetized in this analysis. Potential benefit categories that have not been quantified and monetized are listed in Table IV.D.–8. Unmonetized PM-and ozone-related benefits are indicated by BPM . And B Ozone , respectively.

c B is equal to the sum of all unmonetized benefits, including those associated with PM, ozone, CO, and HAPS.

d These estimates are based on the EPA preferred approach for valuing reductions in premature morality, the VSL approach. Thisapproach and an alternative, age-adjusted approach—the VSLY approach—are discussed more fully in section f above.



### Table IV.D.–10b.—2030 Annual Monetized Costs, Benefits, and
Net Benefits for the Final Tier 2/
Gasoline Sulfur Rule: AlternativeEstimates Using the Value of Statistical Life Years Saved Approach

to Value Reductions in Premature Mortality a

Billion 1997 (dollars)

Adjusted compliance costs ..... $5.3

Monetized PM-related benefits b

. $13.3+BPM

Monetized Ozone-related benefits b

. $0.5+B Ozone

Monetized net benefits c, d ....... $8.5+B

Notes:

a For this section, all costs and benefits arerounded to the nearest 100 million. Thus, figures presented in this chapter may not exactly equal benefit and cost numbers presented in earlier sections of the chapter.

b Not all possible benefits or disbenefits arequantified and monetized in this analysis. Potential benefit categories that have not been quantified and monetized are listed in Table IV.D.–8. Unmonetized PM-and ozone-related benefits are indicated by BPM . And B Ozone , respectively.

c B is equal to the sum of all unmonetized benefits, including those associated with PM, ozone, CO, and HAPS. d The VSLY estimate is calculated by amortizing the $5.9 million mean VSL estimate over the 35 years of life expectancy associated with subjects in the labor market studies used toobtain the VSL estimate. The resulting estimate, using a 5 percent discount rate, is $360,000 per life-year saved in 1997 dollars.This approach is discussed more fully in section f above.

V. Other Vehicle-Related Provisions

The section describes several additional provisions of today’s final rule that were not previously discussed in this preamble. 108

A. Final Tier 2 CO, HCHO and PM
Standards

Tables IV.B.–4 and –5 in Section IV.B.4.a. above presented the Tier 2 standards for carbon monoxide (CO), formaldehyde (HCHO), and particulate matter (PM). The following paragraphs discuss our selection of these specific
standards.

1. Carbon Monoxide (CO) Standards

Beyond aligning carbon monoxide (CO) standards for all LDVs and LDTs, and harmonizing with California vehicle technology, reduction in CO emissions is not a primary goal of the Tier 2 program. However, we note that more
than three-fourths of CO emissions in
1997 came from mobile sources and that there are currently 20 officially designated CO nonattainment areas in
the U.S. These areas include 47 counties with a combined population of 34 million. In addition, there are 23 officially designated maintenance areas also with a combined population of 34 million. Further, CO is a deadly gas that leads to accidental poisoning fatalities and injuries. Also, CO may play a role in ozone formation by increasing the reactivities of VOCs in the atmosphere.

Although there remain many areas of
nonattainment and maintenance for the


### 6788 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

109 We recognize that the standards we are finalizing for interim LDT4s are more stringent than for equivalent vehicles (MDV3s) under Cal LEV I.

Still our interim HLDT standards harmonize with Cal LEV I standards applicable to MDV2s.

110 Ibid. CO NAAQS, and those areas include large populations, the broad trends indicate that ambient levels are being
reduced and the amount of further
reductions needed to meet the CO NAAQS will not be as substantial as for the ozone NAAQS. The reductions in this program will help ensure that
emissions and ambient levels of CO continue to decline, which will
contribute to the attainment and maintenance of the CO NAAQS in
current nonattainment areas. These
standards will also ensure that CO levels do not increase in the future, which could exacerbate any CO
attainment and maintenance concerns. Our analysis estimating of the tons of
CO reduction due to the Tier 2/Gasoline Sulfur program is found in Chapter III
of the RIA.

Thus the CO standards we are finalizing for all Tier 2 LDVs and LDTs are essentially the same as those from the NLEV program for LDV/LLDTs.
These standards will harmonize with CalLEV II CO standards except at California’s SULEV level (EPA Bin 2). This lone divergence will not pose
additional burden to manufacturers
because the federal Tier 2 CO standards for these vehicles will be less stringent than California’s. Bins applicable during the interim programs will include CO values from the NLEV program for LDV/ LLDTs and from the Cal LEV I program
for HLDTs. 109 In our NPRM, we proposed tighter CO standards than California for certain higher bins. Based upon comment, we are aligning our CO
standards with those of California to help ensure that carry over between the two programs can occur. 110 This alignment is consistent with our goal of bringing all LDVs and all categories of
LDTs under common standards that allow for technology to be harmonized to the extent possible with California. Despite these minor changes, we still expect the standards in today’s rule to
lead to CO reductions.

2. Formaldehyde (HCHO) Standards

Similar to our approach to CO standards, we are aligning all Tier 2 LDVs and LDTs under the formaldehyde standards from the NLEV program or CalLEV II program. HLDTs, which are not subject to the NLEV program, will become subject to federal formaldehyde
standards for the first time under the provisions of this rulemaking. Formaldehyde is a hazardous air pollutant and EPA is required to regulate motor vehicle formaldehyde under section 202(l) of the Act. The standards finalized today are primarily
of concern for methanol and methane (compressed natural gas or CNG)-fueled vehicles, because formaldehyde is chemically similar to methanol and methane and is likely to be produced
when methanol or methane are not completely burned in the engine.
HLDTs are not included under the NLEV program and will therefore not face formaldehyde standards as LDVs and LLDTs will in 2001 (1999 in the northeast states). We believe it is appropriate to bring HLDTs under HCHO standards in this rulemaking. Applying formaldehyde standards to HLDTs will be consistent with our goals of aligning standards for all LDVs and LDTs regardless of fuel type and harmonizing technologically with California standards wherever possible
and reasonable and the burden will be minimal. Consequently, we are including formaldehyde standards for HLDTs under the Tier 2 program as well as under the interim programs.

3. Use of NMHC Data To Show Compliance with NMOG Standards; Alternate Compliance With Formaldehyde Standards

In response to comments, we are finalizing a provision to allow
manufacturers to demonstrate compliance with the interim and Tier 2 NMOG standards using NMHC data (non-methane hydrocarbons) for gasoline and diesel vehicles. For these vehicles, NMOG and NMHC emissions are very similar and testing for NMHC is considerably simpler and cheaper than measuring NMOG. Data available
to us show that NMHC emissions at levels expected from interim and Tier 2 LDVs and LDTs can be adjusted to represent NMOG emissions by a small multiplicative factor. We are finalizing to accept NMHC test results to demonstrate compliance with the NMOG standards, but are requiring that the NMHC results be multiplied by 1.04. We will permit the use of other adjustment factors based upon comparative testing.

A drawback to NMHC testing is that NMHC testing does not yield formaldehyde results as NMOG testing
does. We noted in the NPRM that HCHO is actually a component of NMOG and that we expect that all vehicles able to meet the proposed Tier 2 or interim standards (including methanol and CNG-fueled vehicles) will readily comply with the HCHO standards. In fact, based upon a review of certification data, we believe that gasoline and diesel
vehicles will be far below the HCHO standards, perhaps by as much as 90%. (See the Response to Comments document for details)

To reduce testing costs while harmonizing with the CalLEV II standards we are finalizing a provision that will permit manufacturers of gasoline and diesel vehicles to demonstrate compliance with the formaldehyde standards based on engineering judgement. This provision will apply only to diesel and gasoline fueled vehicles and will require
manufacturers to make a demonstration in their certification application that vehicles having similar engine and vehicle size and engine and aftertreatment technologies have been shown to exhibit compliance with the applicable formaldehyde standard for
their full useful life. This demonstration will be similar to that currently required for gasoline vehicles to demonstrate compliance with the particulate matter standard (see 40 CFR 86.1829(b)(1)), and should be readily available from California vehicles where NMOG testing is required and formaldehyde data is routinely generated.

4. Particulate Matter (PM) Standards

We proposed to adopt tighter PM standards. For Tier 2 vehicles, we proposed PM bin values such that PM would consistently be 0.01 g/mi or less. To provide manufacturers with flexibility, we proposed a 0.02 g/mi PM standard for vehicles that certify to the highest Tier 2 bins. As we have indicated elsewhere in this preamble, we anticipate that low sulfur diesel fuel will be available by 2007 to enable
diesel vehicles to utilize advanced diesel technologies and meet these PM
standards.

For the interim standards we proposed a PM standard of 0.06 g/mi for the highest bins. We received
considerable comment from
manufacturers and others about the PM standards we proposed. In the final rule, we are raising the PM standard to 0.08 g/mi for bin 10. For HLDTs, manufacturers would likely have had to use advanced diesel technologies to attain our proposed interim standards and these technologies require low
sulfur diesel fuel. Since we do not expect that fuel to be widely available until the 2006–2007 timeframe, we are raising the PM standard so that diesels are not barred from the interim program by a fuel situation beyond their
manufacturers’ control.

PM standards are primarily a concern for diesel-cycle vehicles, but they also apply to gasoline and other otto-cycle


### 6789 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

111 SFTP requirements do not apply to MDPVs. We plan to address the applicability of SFTP standards and test procedures to MDPVs in a future rulemaking. 112 For vehicles included in the NLEV program, this phase-in becomes a four year phase-in beginning in 2001. vehicles. We will continue to permit otto-cycle vehicles to certify to PM standards based on representative test data from similar technology vehicles.

B. Useful Life

The ‘‘useful life’’ of a vehicle is the period of time, in terms of years and miles, during which a manufacturer is formally responsible for the vehicle’s emissions performance. For LDVs and LDTs, there have historically been both ‘‘full useful life’’ values, approximating the average life of the vehicle on the road, and ‘‘intermediate useful life’’ values, representing about half of the vehicle’s life. We proposed and are finalizing several changes to the current useful life provisions for LDVs and

LDTs.

1. Mandatory 120,000 Mile Useful Life

We are finalizing our proposal to equalize full useful life values for all Tier 2 LDVs and LDTs at 120,000 miles. Congress, in directing EPA to perform the Tier 2 study, also directed EPA to consider changing the useful lives of
LDVs and LDTs. Manufacturers have made numerous advances in quality, materials and engineering that have led to longer actual vehicle lives and data show that each year of a vehicle’s life, people are driving more miles. Current data indicate that passenger cars are driven approximately 120,000 miles in their first ten years of life. Trucks are driven further. Current regulatory useful lives are 10 years/100,000 miles for LDV/LLDTs and 11 years/120,000 miles for HLDTs. We project, based on our Tier 2 model, that approximately 13 percent of light-duty NO X and 11 percent of light-duty VOCs is produced between 100,000 and 120,000 miles. Given the trend toward longer actual
vehicle lives and increases in annual mileage, we believe that it is reasonable to extend the regulatory useful life requirements California, in its LEV II program, has adopted full useful life
standards for all LDVs and LDTs of 10 years or 120,000 miles, whichever occurs first. The time period for federal LDV/LLDTs will be 10 years, but will remain at 11 years for HLDTs consistent
with the Clean Air Act. Intermediate useful life values, where applicable, will remain at 5 years or 50,000 miles,
whichever occurs first. Where manufacturers elect to certify Tier 2 vehicles for 150,000 miles to gain
additional NO X credits, as discussed below, the useful life of those vehicles will be 15 years and 150,000 miles. We are not harmonizing with California on the mandatory useful life for evaporative emissions of 15 years and 150,000 miles, but rather this useful life will be mandatory for evaporative emissions only when a manufacturer elects optional 150,000 mile exhaust
emission certification.

We proposed to extend the useful life of interim LDV/LLDTs to 10 years/ 120,000 miles beginning in 2004. Based upon extensive comment, we are not finalizing that provision and the useful
lives of interim LDV/LLDTs will remain unchanged to help facilitate their carryover from the NLEV program into the interim program. Commenters provided persuasive argument that the proposed provision, along with others, would impose a large workload burden on manufacturers because they would be unable to carry over certification data from 2003 and would have to recertify virtually all of their LDV/LLDTs in
2004. Manufacturers stressed that this would be an especially unproductive
use of their resources because these
vehicles would all have to be recertified again as they were phased into the Tier
2 standards between 2005 and 2007. This change in the final rule will have only minimal impact on the benefits of

our program.

2. 150,000 Mile Useful Life Certification Option

We are adopting as proposed a provision to provide additional NO X credit in the fleet average calculation for
vehicles certified to a useful life of 150,000 miles. A manufacturer certifying a test group to a 150,000 mile useful life will incorporate those vehicles into its corporate NO X average as if they were certified to a full useful life standard 0.85 times the applicable 120,000 mile NO X standard. To use this option, the manufacturer will have to agree to (1) certify the engine family to the applicable 120,000 mile exhaust and evaporative standards at 150,000 miles for all pollutants; and (2) increase the mileage on the single extra-high mileage
in-use test vehicle from a minimum of 90,000 miles to a minimum of 105,000
miles.

Today’s vehicles are lasting longer and being driven farther than those built in past years and we believe it is reasonable to encourage the development of more durable emission control systems. Consequently we believe it is appropriate to provide incentives to manufacturers to certify
their vehicles to extended useful lives beyond 120,000 miles. This is why we proposed and are today finalizing
additional NO X credits for Tier 2
vehicles certified to a useful life of 150,000 miles.

In the final rule we are adding an option that, for a test group certified to a 150,000 mile useful life, the manufacturer may choose between the
additional credits or a waiver of
intermediate life standards. Commenters suggested that some vehicles would be discriminated against by our intermediate life standards, because they might have flat deterioration curves, and could meet our full life standards, but not the lower
intermediate life standards. We are reluctant to give up our intermediate life standards, because we believe they provide an additional measure of certainty that vehicles will meet standards. Nonetheless, we believe that certification to a longer useful life is an important goal and that manufacturers who do so will likely use technologies that have very flat deterioration curves. This option provides manufacturers with the flexibility to certify vehicles without having to comply with intermediate life standards. In exchange they must comply with full life standards for considerably longer mileage.

C. Supplemental Federal Test Procedure (SFTP) Standards 111

1. Background

Supplemental Federal Test Procedure (SFTP) standards require manufacturers
to control emissions from vehicles when operated at high rates of speed and acceleration (the US06 test cycle) and when operated under high ambient temperatures with air conditioning loads (the SC03 test cycle). The existing light duty SFTP requirements begin a three year phase-in in model year 2000
for Tier 1 LDV/LLDTs. 112 For HLDTs, SFTP requirements begin a similar phase-in in 2002. Intermediate and full
useful life SFTP standards exist for all categories of Tier 1 vehicles except that SFTP standards do not apply to diesel
fueled LDT2s and HLDTs. Table V.A.–
1 shows the full useful life federal SFTP requirements applicable to Tier 1
vehicles.


### 6790 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

113 This disparity arose because neither EPA nor

CARB had full useful life SFTP standards for LEVs or ULEVs when the NLEV program was adopted. Since a major requirement of the NLEV program was harmony with California standards, EPA adopted the California SFTP standards in place for the NLEV time frame (2001 and later).

114 Except that, we proposed to permit TLEV vehicles (EPA interim Bin 10 in Table IV.B.–4), which are not subject to new SFTP standards under NLEV, to continue to meet Tier 1 SFTP standards, and to permit HLDTs under the interim programs

to continue to meet Tier 1 SFTP standards that do not fully phase in until the 2004 model year. 

### TABLE 

### V.A.–1.—F ULL 

### U SEFUL 

### L IFE 

### F EDERAL 

### SFTP STANDARDS 

### A PPLICABLE TO 

### T IER 

### 1 V EHICLES

Vehicle category NMHC + NOX (weighted g/ mi) a CO (g/mi) b

US06 SC03 Weighted

LDV/LDT1 (gasoline) ....................................................................................... 0.91 11.1 3.7 4.2 LDV/LDT1 (diesel) ........................................................................................... 2.07 11.1 — 4.2

LDT2 ................................................................................................................ 1.37 14.6 5.6 5.5
LDT3 ................................................................................................................ 1.44 16.9 6.4 6.4

LDT4 ................................................................................................................ 2.09 19.3 7.3 7.3

Notes:

a Weighting for NMHC+NOX and optional weighting for CO is 0.35x(FTP)+0.28x(US06)+0.37x(SC03).

b CO standards are stand alone for US06 and SC03 with option for a weighted standard.

2. SFTP Under the NLEV Program

The NLEV program includes SFTP requirements for LDVs, LDT1s and LDT2s. These requirements impose the

Tier 1 intermediate and full useful life

SFTP standards on Tier 1 and TLEV vehicles, but impose only 4000 mile standards adopted from California LEV I program on LEVs and ULEVs. 113

NLEV SFTP standards for LEVs and
ULEVs are shown in Table V.A.–2.
Table V.A.–2 also includes the
California LEV I SFTP standards for
LDT3s and 4s. The standards in that table do not provide for a weighted standard for NMHC+ NO X or for CO, but rather employ separate sets of standards for the US06 and SC03 tests. Also, while

the NLEV and CAL LEV I SFTP standards apply to gasoline and diesel vehicles, they do not include a standard for diesel particulates (PM).



### TABLE 

### V.A.–2.—SFTP STANDARDS FOR 

### LEVS AND 

### ULEVS IN THE 

### NLEV/CAL 

### LEV I P ROGRAM

[4000 Mile Standards]

US06 SC03

NMHC+NOX (g/ mi) CO (g/mi) NMHC+NOX (g/mi) CO (g/mi)

LDV/LDT1 ...................................................................................................... 0.14 8.0 0.20 2.7

LDT2 .............................................................................................................. 0.25 10.5 0.27 3 .5 LDT 3 (Calif MDV 2) ...................................................................................... 0.4 10.5 0.31 3.5 LDT 4 (Calif MDV 3) ...................................................................................... 0.6 11.8 0.44 4.0

3. SFTP Standards for Interim and Tier 2 LDVs and LDTs: As Proposed

Since no significant numbers of
vehicles certified to SFTP standards will enter the fleet until 2001, manufacturers raised concerns during the development of the NPRM regarding significant changes to the SFTP program before its implementation. We stated in the NPRM
that it was reasonable not to increase SFTP stringency beyond NLEV/CalLEV I levels for the Tier 2 program, but we proposed to include SFTP standards adjusted for intermediate and full useful
life deterioration where there are currently only 4000 mile standards.

Full useful life standards for Tier 2
vehicles are consistent with our
mandate under the Clean Air Act. We
derived the full and intermediate useful life standards in the NPRM by applying
deterioration allowances from our draft MOBILE 6 model to the existing 4000
mile standards for LDVs and LLDTs. For HLDTs we applied similarly derived
deterioration allowances to California’s LEV I SFTP standards for MDV2s and MDV3s, which are the corresponding categories to LDT3s and LDT4s in the California LEV I program. The full and
intermediate useful life SFTP standards we proposed would have applied to all Tier 2 vehicles including Tier 2 LDT3s and LDT4s. Further, since our interim
standards are derived from NLEV and Cal LEV I standards, we proposed that
our full life SFTP standards would apply to all interim LDV/LLDTs beginning in 2004. 114

4. Final SFTP Standards for Interim and
Tier 2 LDVs and LDTs

Based upon extensive comment from manufacturers, we are persuaded that our proposed intermediate and full life
SFTP standards need more review and should possibly be reexamined in a separate rulemaking. Manufacturers were quite concerned that the technique
we used to obtain the intermediate and
full life SFTP standards led to standards that were overly stringent. They argued that they have little experience with SFTP compliant vehicles given the current infancy of the program and they
do not know whether SFTP emissions can be reasonably be expected to
deteriorate like FTP emissions. Consequently, in today’s notice, we are finalizing a program that will adopt the existing NLEV/Cal LEV I 4000 mile standards and utilize adjusted full life standards from the Tier 1 program, instead of values derived by applying
the draft MOBILE 6 model.

These standards will apply to all Tier
2 vehicles and to all interim LDV/ LLDTs. We proposed and are finalizing
that interim HLDTs meet Tier 1 SFTP
standards which do not finish their phase-in until the 2004 model year.

With regard to intermediate and full life SFTP standards, the preamble to the final rule implementing the SFTP program for the Tier 1 SFTP emission standards (61 FR 54856) provided a formula for computing SFTP standards to apply under more stringent future


### 6791 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

115 The 4,000 mile standards under NLEV are phased-in in such a way that diesels would not likely be subject to them until the 2004 model year, given their very small market share. Today’s rulemaking effectively supercedes the NLEV program beginning with the 2004 model year. In other words, while NLEV contains 4,000 mile SFTP standards for diesels, they are not likely to ever impact diesel LDV/LLDTs. FTP standards. In the Tier 1 program, SFTP standards represent a weighted average of FTP, US06 and SC03 standards. The three components are weighted by factors of 0.35, 0.28, and 0.37 respectively. The formula simply adjusts the Tier 1 SFTP weighted average standards downward to reflect the decrease in the component FTP standards. The weighting factors remain
the same and the US06 and SC03 standards remain the same, but the SFTP standard becomes tighter because the FTP component becomes smaller.
These standards will take effect for all LDV/LLDTs beginning in 2004 and will phase in with the Tier 2 standards for
HLDTs in 2008 and 2009. The formula
is as follows:

New SFTP Standard = Old SFTP Standard

¥ [0.35 × (Tier 1 FTP standard ¥ New FTP Standard)]

In today’s final rule, we will employ this formula to compute full useful life
SFTP standards for all Tier 2 vehicles
and for interim LDV/LLDTs. Because we are also adopting the California 4000 mile SFTP standards for these vehicles, we are not adopting intermediate life SFTP standards, so as to avoid the
burden of three sets of SFTP standards.

LDT3 and LDT4 SFTP standards do not currently apply to diesels. Further, the standards applicable to Tier 1 diesel LDVs and LDT1s are less stringent than gasoline standards and do not apply to the SC03 cycle. There are no SFTP
standards under Tier 1 for diesel LDT2s. In this final rule, we are applying the same approach we are using with other
standards in this document to the Tier
2 and interim SFTP standards. Consequently, we are finalizing that
Tier 2 vehicles and interim LDV/LLDTs with diesel or gasoline engines must comply with the same NMHC+NO X and CO SFTP limits. Thus, in computing
Tier 2 SFTP full life standards for diesel LDVs and LDT1s from Tier 1 values, the
values for diesels must be determined from the standards applicable to gasoline vehicles of the same category.

Because we lack certainty as to whether diesel vehicles can comply with the 4,000 mile SFTP standards for gasoline vehicles that we are adopting from the NLEV and Cal LEV I programs, we are providing an option that diesel LDV/LLDTs may comply with
intermediate life SFTP standards
instead. 115 Manufacturers must calculate intermediate life standards using the same approach described for full life standards, but must substitute appropriate intermediate life values in the equation above. This provision will only apply through model year 2006, and thus will likely only impact interim non-Tier 2 vehicles, given the very small market share that diesels occupy and given our expectation that they will be the last LDV/LLDTs phased into Tier
2 standards. We noted above that
interim non-Tier 2 HLDTs will have the option of meeting Tier 1 SFTP
standards. Thus diesel HLDTs will not have to comply with the 4,000 mile standards in the interim years and the option we are providing for LDV/LLDTs
is not needed for HLDTs.

5. Adding a PM Standard to the SFTP
Standards

We requested comment on the appropriate SFTP PM standards for diesel vehicles. We suggested it would be appropriate to establish a margin above the applicable FTP PM standard
to serve as the SFTP standard. EPA has implemented such margins in recentconsent decrees, under which heavyduty engine manufacturers have agreed
not to exceed emission levels 1.25 times the applicable exhaust standards (including PM standards) when engines are operated over a wide range of operating conditions. We received
comments in favor of an SFTP PM
standard of 1.25 times the FTP standard and we received many comments from manufacturers against setting any SFTP
PM standard until more data become
available.

We believe it is reasonable to include an SFTP standard for PM. However, we
are uncertain as to the technical appropriateness of the 1.25 value for passenger vehicles. Further, the 1.25
value would lead to an SFTP standard
for PM that would not match the stringency of the other SFTP standards we are finalizing. Consequently, we are finalizing a procedure for computing diesel PM standards that is nearly identical to the procedure for computing weighted SFTP standards for

NMHC+NO X and CO described above. We believe standards computed in this way will be readily feasible for both gasoline and diesel vehicles.

To compute the SFTP PM standards,
manufacturers will use the same
formula described above for

NMHC+NO X and CO. Where that
formula calls for the Tier 1 SFTP standard to be inserted, manufacturers
must insert the Tier 1 FTP standard. This is because, under Tier 1 standards,
there is no SFTP standard for PM. However, the Tier 1 weighted SFTP standards are equal to the Tier 1 FTP standards (or the sum of the Tier 1 FTP
standards in the case of NMHC+NOX). Using the Tier 1 FTP PM standards in this way will lead to a Tier 2 SFTP PM standard whose stringency is appropriately matched to the other pollutants.

For HLDTs , we proposed and are finalizing that Tier 1 SFTP standards would apply through the interim program. because of the late start of SFTP phase-in for Tier 1 vehicles. We see no reason to impose SFTP PM standards on these vehicles during the interim period when their manufacturers will be under pressure to develop diesel vehicles to comply with the Tier 2 standards. Also, if we were to impose an FTP PM standard on the interim vehicles, it would likely be matched to the interim phase in for
HLDTs and manufacturers would simply defer compliance for diesels until the last phase-in year (2007). The
manufacturers would then have to recertify to the Tier 2 standards by 2009. Given the relatively small number of diesel vehicles, we believe the most reasonable approach is to defer SFTP
PM standards for HLDTs until the Tier 2 phase-in. Consequently, we are finalizing that Tier 2 HLDTs will have to comply with an SFTP PM standard computed as described above.

For LDV/LLDTs we are also including
the SFTP PM standard for the Tier 2 vehicles. There are only a few diesel LDV/LLDTs currently produced and no large increase in their numbers is expected. We see little environmental benefit in imposing the SFTP PM
standard on interim vehicles.

6. Future Efforts Relevant to SFTP
Standards

We are very concerned about ‘‘off cycle’’ emissions, i.e. those emissions that occur under vehicle operational modes that are not captured in the FTP. SFTP standards help to address our concerns and we believe that they should apply to all vehicles, regardless of fuel. Our final rule essentially promulgates Tier 1 SFTP standards that are reduced to represent the reduction in the FTP component standards. As we
indicate under our discussion of SFTP for medium duty passenger vehicles (see section IV.B.4.g) we expect to conduct a rulemaking to establish appropriate
‘‘Tier 2’’ SFTP standards for all Tier 2 vehicles. In that rule, we expect to
reexamine the US06 and SC03 test cycles and their applicability to vehicles using different fuels and technologies,


### 6792 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

116 The Compliance Assurance Program, (64 FR 23906) takes effect in the 2000 model year. including whether these cycles are the most appropriate ones for diesels. We
will also examine whether it is necessary to have different sets of
standards for different vehicle sizes or whether it is possible to establish one
set of standards for all vehicles.

D. LDT Test Weight

Historically, HLDTs (LDT3s and LDT4s) have been emission tested at their adjusted loaded vehicle weight (ALVW), while LDVs, LDT1s, and
LDT2s have been tested at their loaded vehicle weight (LVW). ALVW is equivalent to the curb weight of the truck plus half its maximum payload, while LVW is equivalent to the curb weight of the truck plus a driver and one adult passenger (300 pounds). As we are equalizing standards and useful lives across LDVs and all categories of LDTs, we believe it is appropriate to test
all the vehicles under the same conditions. Therefore, we are finalizing as proposed to test HLDTs at their loaded vehicle weight. We believe this is appropriate because the standards we are imposing on HLDTs under Tier 2 are considerably more stringent than the Tier 1 standards. Further, one of our reasons for bringing HLDTs under the same standards as passenger cars is that these trucks include many vans and sport utility vehicles that are often used as passenger cars with just one or two passengers. Lastly, we note that testing
HLDTs at LVW is consistent with the way they have been tested for fuel economy purposes for many years. Consequently, we believe it is appropriate to test them at LVW.

The NPRM proposed that all HLDTs would certify using LVW beginning in the 2004 model year. Based upon comments, the final rule will allow the
certification of HLDTs based on ALVW until those vehicles are phased into the
Tier 2 standards in 2008 and 2009 at which time they must be tested at LVW. This will enhance carryover of
California vehicles to the Federal interim program in cases where the
California vehicles meet our interim
standards.

E. Test Fuels

As discussed elsewhere in this preamble, the NLEV program was adopted virtually in its entirety from California’s program. Because California’s standards were developed
around the use of California Phase II reformulated gasoline (RFG) as the exhaust emission test fuel, we adopted
California Phase II test fuel as theexhaust emission test fuel for gasolinefueled vehicles in the federal NLEV program, although we recognized at the time that vehicles outside of California would be unlikely to operate on that fuel in use. In the NPRM we proposed interim programs that were derived from NLEV (for LDV/LLDTs) and the CAL LEVI program (for HLDTs), and we proposed to accept certification test results generated on California fuel, but indicated that we might test or require in-use testing on federal fuel.

Based upon comment we are finalizing provisions to permit, for interim vehicles, that if a test group has
been certified to the exhaust emission standards using California fuel and is being carried into the interim program from NLEV or is being carried across from California LEV I certification, then we will not test or require in-use exhaust testing on federal fuel. This change is intended to help address
recertification workload concerns raised by manufacturers. For new certification
not carried across from California LEV I or carried over from NLEV, and for any Tier 2 vehicles, we will accept exhaust
certification test results based on California fuel for 50 state vehicles only, but we will reserve the right to perform or require certification confirmatory testing and in-use testing on federal test
fuel.

We recognize that manufacturers may want to perform calibration changes on
vehicles carried across from the California LEV I program or carried over from NLEV program. These calibration changes will likely be aimed at certifying the test group to the lowest possible NO X value. We believe that these calibration changes would be appropriate, provided they can still be covered by the existing worst case durability data vehicle. We will perform or require certification confirmatory testing and in-use emission testing on these vehicles using California fuel.

Because differences exist between the California and federal evaporative emission testing procedures, we proposed to continue to require the use
of federal certification fuel as the test fuel in evaporative emission testing. Under current programs, where California and federal evaporative emission standards are essentially the same, California accepts evaporative results generated on the federal procedure (using federal test fuel),
because available data indicates the federal procedure to be a ‘‘worst case’’ procedure. The evaporative standards California has adopted for their LEV II program are more stringent than those we are finalizing in this document. In the NPRM, we requested comment and supporting emission test data on
whether vehicles certified to CalLEV II evaporative standards using California fuels will necessarily comply with the federal Tier 2 evaporative standards, including ORVR standards, when tested with federal test fuel. While we got
comments from manufacturers advocating that we accept the results of California evaporative testing to demonstrate compliance with the federal evaporative standards, we received no supporting data. Still, given the fairly large difference between California and federal evaporative standards, it seems reasonable that a vehicle meeting the California standards
under California fuels and test conditions might also meet federal
standards under federal fuels and conditions. We believe it may be possible for manufacturers to establish a relationship between the two sets of standards, fuels and conditions that would enable us to grant federal certification based upon data showing conformity with the California
standards under California fuels and conditions. Consequently, we are including a provision in the certification regulations to enable manufacturers to obtain federal evaporative certification based upon California results, if they obtain advance approval from EPA. EPA
will review test data from manufacturers to establish whether it is appropriate to accept California data to demonstrate compliance with federal standards.

F. Changes to Evaporative Certification Procedures To Address Impacts of
Alcohol Fuels

Current certification procedures, including regulations under the new CAP2000 program, 116 allow manufacturers to develop their own durability process for calculating deterioration factors for evaporative emissions. The regulations (§ 86.1824– 01) permit manufacturers to develop service accumulation (aging) methods based on ‘‘good engineering judgement’’. The manufacturer’s durability process must be designed to predict the expected evaporative
emission deterioration of in-use vehicles over their full useful lives. We proposed and are finalizing requirements that these aging methods include the use of
alcohol fuels to address concerns that alcohol fuels increase the permeability and thus the evaporative losses from hoses and other evaporative components. Based upon comment, we are also finalizing an option to the requirement that the manufacturer use the alcohol fuel. Under this option, the manufacturer may demonstrate to EPA using good engineering judgement


### 6793 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

117 Numerous SAE papers examine the permeability of fuel and evaporative system

materials as well as the influence of alcohols on permeability. See, for example SAE Paper #s

910104, 920163, 930992, 970307, 970309, 930992, and 981360, copies of which are in the docket for this rulemaking.

118 Ibid. 119 California Exhaust Emission Standards and Test Procedures for 2003 and Subsequent Model Zero-Emission Vehicles, and 2001 and Subsequent Model Hybrid Electric Vehicles. In the Passenger Car, Light-Duty Truck and Medium-Duty Vehicle Classes; adopted August 5, 1999. acceptable to EPA that its durability process for calculating evaporative emission deterioration factors accurately predicts deterioration under prolonged exposure to alcohol fuels.

We have reviewed data indicating that the permeability, and therefore the evaporative losses, of hoses and other evaporative components can be greatly increased by exposure to fuels containing alcohols. 117 Alcohols have been shown to promote the passage of hydrocarbons through a variety of different materials commonly used in evaporative emission systems. Data from component and fuel line suppliers indicate that alcohols cause many elastomeric materials to swell, which opens up pathways for hydrocarbon permeation and also can lead to distortion and tearing of components like ‘‘O’’ ring seals. Ethers such as
MTBE and ETBE have a much smaller
effect. Alcohol-resistant materials such
as fluoroelastomers are available and are currently used by manufacturers to varying extents.

Alcohols do not impact evaporative components and hoses immediately, but rather it may take as long as one year of exposure to alcohol fuels for permeation
rates to stabilize. The end result is higher permeation and increased in-use evaporative emissions. 118

Today, roughly 10% of fuel sold in the U.S. contains alcohol, mainly in the form of ethanol, and such fuels are often
offered in ozone nonattainment areas. We believe it is appropriate to ensure that evaporative certification processes expose evaporative components to alcohols and do so long enough to stabilize their permeability. Therefore, we are finalizing our proposal to the evaporative certification requirements to require manufacturers to develop their deterioration factors using a fuel that contains the highest legal quantity of
ethanol available in the U.S.

To implement this change, we are modifying the Durability Demonstration Procedures for Evaporative Emissions found at § 86.1824–01. The amendments will require manufacturers not using an approved option, to age their systems using a fuel containing the maximum concentration of alcohols allowed by
EPA in the fuel on which the vehicle is intended to operate, i.e., a ‘‘worst case’’ test fuel. (Under current requirements, this fuel would be about 10% ethanol, by volume.) We are also modifying the Durability Demonstration Procedures to require manufacturers to ensure that their aging procedures are of sufficient duration to stabilize the permeability of the fuel and evaporative system
materials. These modifications will take place as vehicles are phased into the evaporative emission standards
contained in this final rule.

We requested comment on alternative ways by which manufacturers could
document or demonstrate that their components are made of materials whose permeability is not significantly affected by alcohols. We received no comments responsive to this request,
but we did receive comments that EPA should not change the CAP2000 provision allowing manufacturers to develop their own durability process for calculating evaporative emission deterioration factors ‘‘using good engineering judgement’’. We do not wish to foreclose the possibility that an alternative method may exist or may arise in the future. Consequently, in the final rule we will permit manufacturers to use an optional method based on good engineering judgement acceptable to EPA. As an example, one method
would be for the manufacturer to show that it is exclusively using materials
documented in the technical literature to have low permeability in the presence of alcohols.

G. Other Test Procedure Issues

California’s LEV II program implements a number of minor changes to exhaust emissions test procedures. We have evaluated these changes and found that, for tailpipe emissions, the California test procedures fall within ranges and specifications permitted
under the Federal Test Procedure.

With regard to hybrid electric vehicles (HEVs) and zero emission vehicles (ZEVs), we believe that these vehicles will be predominantly available in California, or that they will typically be first offered for sale in California,
because of California’s ZEV requirement, which promotes the sale of
HEVs and ZEVs. Where manufacturers
market HEVs or ZEVs outside of California, it is likely that they will
market the same vehicles in California. Consequently, we are finalizing our proposal to incorporate by reference
California’s exhaust emission test procedures for HEVs and ZEVs. 119 In the NLEV program, we provided a specific formula used by California that could be used to compute an HEV
contribution factor to NMOG emissions.
This formula took into consideration the range without engine operation of various types of HEVs and had the effect of reducing the NMOG emission standard for a given emission bin (for HEV vehicles only). This would have
obvious beneficial effects on a
manufacturer’s calculation of its corporate NMOG average.

The technology of HEVs is under rapid change and we do not believe that we can design a formula now that will accurately predict the impact of HEVs on corporate average NO X emissions in the Tier 2 time frame. Consequently, we are finalizing the proposed provision by which manufacturers could propose
HEV contribution factors for NO X to EPA. If approved, these factors can be
used in the calculation of a manufacturer’s fleet average NOx emissions and will provide a
mechanism to credit an HEV for operating with no emissions over some portion of its life.

These factors will be based on good engineering judgement and will consider such vehicle parameters as vehicle weight, the portion of the time during the test procedure that the vehicle operates with zero emissions, the zero emission range of the vehicle,

NO X emissions from fuel-fired heaters and any measurable NO X emissions from on-board electricity production and storage.

The final NLEV rule ( See 62 FR pg 31219, June 6, 1997) incorporated by
reference California’s NMOG measurement procedure and adopts California’s approach of using Reactivity Adjustment Factors (RAFs) to adjust
vehicle emission test results to reflect differences in the impact on ozone
formation between an alternative-fueled
vehicle and a vehicle fueled with conventional gasoline. As has been discussed elsewhere in this preamble, the NLEV program is a special case in
which California standards and provisions were adopted virtually in their entirety. In the preamble to the final NLEV rule ( See 62 FR 31203), we expressed our reservations about the use
of RAFs. We also addressed our reservations about the use of reactivity factors developed in California in a program that spans a range of climates and geographic locations across the
United States in the final rule on reformulated gasoline (RFG) (see 59 FR 7220). We continue to be concerned about the validity of RAFs to predict
ozone formation nationwide and asked the National Academy of Sciences to


### 6794 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

120 Ozone-Forming Potential of Reformulated Gasoline, May 1999. National Academy of Sciences; National Academy Press. Available from the NAS web site: http://www.nap.edu.

121 California Evaporative Emission Standards and Test Procedures for 2001 and Subsequent Model Motor Vehicles. Adopted August 5, 1999. 122 We define small volume manufacturers to be those with total U.S. sales of less than 15,000 highway units per year. Independent commercial importers (ICIs) with sales under 15,000 per year

are included under this term.

123 For a graphical illustration of the phase-ins through time, see Table IV.B.–2.

124 2005–2006 for vehicles where the small

volume manufacturer commences its 2004 model year for all its 2004 vehicles before the fourth anniversary date of the signature of this rule. look at the scientific evidence in support of the use of these factors nationwide. While we have recently received a report from NAS, 120 we have not yet developed a final position on
how RAFs should be treated in federal regulations. We are finalizing as proposed not to permit the use of RAFs in the Tier 2 program.

The issue of RAFs is relevant primarily to alcohol and CNG-fueled
vehicles. RAFs are not relevant at all if
a manufacturer elects to use NMHC data to show compliance with the NMOG standards. While, in our final rule,
alcohol and CNG vehicles will have to comply with NMOG standards beginning in 2004 and while we desire
to harmonize with California when practical and reasonable, we will not permit the use of RAFs for Tier 2
vehicles and interim non-Tier 2 vehicles. We note that we are finalizing a provision from the NPRM that permits
dual fueled and flexible fueled vehicles
to elect an NMOG value from the next higher bin when they are tested on an alternative fuel. This provides flexibility in compliance with applicable NMOG
standards for these vehicles. We do not
believe that dedicated alcohol or CNG vehicles should have any problems complying with the NMOG standards we are finalizing and consequently the relief these vehicles might get when RAFs are employed is unnecessary.

In its LEV II program, California is also implementing a number of changes to evaporative emission test procedures. 121 Many of these changes address the evaporative emission testing of hybrid electric vehicles. We proposed not to adopt California’s changes,
because California uses different test temperatures and different test fuel in its evaporative emission testing of gasoline vehicles than we use in the federal program. The preamble to the final NLEV rule ( See 62 FR 31227) explains that California and EPA are reviewing an industry proposal to
streamline and reconcile the California and federal procedures. That work has not been completed. However, where California adopts procedures specific to HEVs and ZEVs, we are adopting those procedures, except that our testing will occur at lower temperatures, and use a fuel determined by EPA to be representative of federal usage (for HEVs only). H. Small Volume Manufacturers

Our final rule includes the following
flexibilities intended to assist all manufacturers in complying with the stringent proposed standards without harm to the program’s environmental goals as presented in the NPRM:

• A four year phase-in of the standards for LDV/LLDTs;

• A delayed phase-in for HLDTs;

• The freedom to select from specific bins of standards;

• A standard that can be met through averaging, banking and trading of NOX credits;

• Provisions for NO X credit deficit carryover; and,

• Provisions for alternative phase-in
schedules.

These flexibilities apply to all manufacturers, regardless of size, and in general we believe they eliminate the need for more specific provisions for
small volume manufacturers. 122 However, we proposed and are finalizing one additional flexibility for small volume manufacturers. Today’s rule exempts small volume manufacturers from the 25%, 50% and 75% Tier 2 phase-in requirements applicable to the 2004, 2005 and 2006 LDV/LLDTs and the 50% phase-in requirement applicable to 2008 HLDTs. Instead, small volume manufacturers will simply comply with the appropriate Tier 2 100% requirement in the 2007 and 2009 model year. In the phase-in years, small volume manufacturers will simply comply with the appropriate interim standards for all of their vehicles, except that we will also exempt small volume manufacturers from the 25%, 50% and 75% phase-in requirements for the 0.20 g/mi corporate average NO X standard applicable to interim HLDTs in 2004–
2006. Small volume HLDT manufacturers must simply comply with the interim standards, including the corporate average NO X standard, in 2007 for 100% of their vehicles. During model years 2004–2006, these same
small volume manufacturers must comply with any of the applicable bins of standards for 100% of their

HLDTs. 123, 124 Provisions to deal
with the leadtime issue related to
HLDTs and outlined in section IV.B. apply to small volume manufacturers.
Therefore unless the small volume manufacturer wants to use the optional
NMOG standards for interim LDT2s and LDT4s, it may optionally meet the Tier 1 standards for its 2004 model year HLDTs, provided it commences its model year for those vehicles before the fourth anniversary date of today’s rulemaking.

As explained in the NPRM, we will continue to apply the federal small volume manufacturer provisions, which provide relief from emission data and durability showing and reduce the amount of information required to be
submitted to obtain a certificate of conformity. In addition, the CAP2000 program contains reduced in-use testing requirements for small volume
manufacturers.

Exempting small volume
manufacturers from the Tier 2 and interim HLDT phase-in requirements eliminates a dilemma that phase-in percentages can pose to a manufacturer that has a limited product line, i.e., how to address percentage phase-in requirements if the manufacturer makes vehicles in only one or two test groups. We have implemented similar provisions for small entities in other rulemakings. Approximately 15–20 manufacturers that currently certify vehicles, many of which are independent commercial importers (ICIs), will qualify. These manufacturers represent just a fraction of one percent of LDVs and LDTs produced. We do not believe that this provision will have any measurable impact on air quality.

1. Special Provisions for Independent Commercial Importers (ICIs)

We requested comment in the NPRM as to whether ICIs should be exempted from the interim and Tier 2 fleet average

NO X standards. We explained that ICIs may not be able to predict their sales and control their fleet average emissions because they may be dependent upon vehicles brought to them by individuals attempting to import uncertified
vehicles. We noted that the NLEV program is optional for ICIs and that ICIs are specifically prohibited, under existing regulations, from complying with the fleet average NMOG standard under the NLEV program. ( See 40 CFR 85.1515(c)). Also, the existing regulations specifically bar ICIs from participating in any emission related averaging, banking or trading program. ( See 40 CFR 85.1515(d)). We expressed
our concern that if we do not amend this provision, ICIs would likely just pick the least stringent bin available to certify their vehicles. This would create an inequity for other manufacturers,


### 6795 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

especially other small volume manufacturers that must comply with the fleet average NO X standards.

Since we do not believe it is wise to finalize a provision that could lead to an inequity like this, and since averaging may not be workable for ICIs, we are finalizing that ICIs must comply with
the standards from the bin that contains the relevant fleet average NO X standard,

e.g., in model years 2007 and later an
ICI would have to use bin 5 or below for all of its LDV/LLDTs. However, if an ICI is able to purchase credits or to certify to bins below the one containing the fleet average NO X standard, we will permit the ICI to bank credits for future use. Where an ICI desires to certify to bins above the fleet average standard, we will permit them to do so if they have adequate and appropriate credits. Where an ICI desires to certify to bins above the fleet average standard and does not have adequate or appropriate credits to offset the vehicles, we will permit the manufacturer to obtain a certificate for vehicles using those bins,
but will condition the certificate such that the manufacturer can only produce
vehicles if it first obtains credits from
other manufacturers or from other vehicles certified to lower bins during that model year.

We do not believe that ICIs can predict or estimate their sales of various vehicles well enough to participate in a program that will allow them leeway to produce some vehicles to higher bins now, knowing that they will sell
vehicles from lower bins later. We also do not believe that we can reasonably
assume that an ICI that certifies and produces vehicles one year, will certify or even be in business the next, consequently, we are also not permitting ICIs to utilize the deficit carryforward provisions of the rule.

Essentially, ICIs will be allowed the major benefits of the averaging, banking and trading program, but will be constrained from getting into a situation where they can ever produce vehicles to higher bins that they can not cover with credits at the time they produce the
vehicles.

2. Hardship Provision for Small Volume
Manufacturers

The panel convened under the Small Business Regulatory Enforcement
Fairness Act recommended that we seek comment on the inclusion of a hardship provision. We requested comment on
whether we should include such a provision in the NPRM. Based upon comment, we are including a limited hardship provision in the final rule that will be applicable to small volume
manufacturers. Small volume manufacturers include companies that independently import motor vehicles (Independent Commercial Importers or ICIs), companies that modify vehicles to operate on alternative fuels, companies that produce specialty vehicles by modifying vehicles produced by others, and companies that produce small quantities of their own vehicles, but rely on major manufacturers for engines and
other vital emission related components. In these businesses, predicting sales is difficult and it is often necessary to rely on others for technology.

This provision will provide limited
relief in the case where a small volume manufacturer is unable to comply with the phase-in dates or average NOX standard. The manufacturer will need to provide evidence that, despite its best efforts, it cannot meet implementation dates or required NO X averages.

Appeals for hardship relief must be made in writing, must be submitted
before the earliest date of noncompliance, must include evidence that the noncompliance will occur despite the manufacturer’s best efforts to comply and must include evidence that severe economic hardship will be faced by the company if the relief is not granted. Hardship relief will only be granted for the first year after a new standard is finally implemented. For small volume manufacturers, which are already exempted from the phase-in
schedules for the interim and Tier 2 programs, this means that relief would be available for the final phase-in year for the LDV/LLDT Tier 2 phase-in (2007), for the final phase-in year for the interim HLDT phase-in (2007), and the final phase-in year for the Tier 2 HLDT phase-in (2009). Relief will also be
available for manufacturers that did not opt into NLEV and must meet our
interim standards for all their LDV/ LLDTs in 2004, and relief will be
available for HLDTs and MDPVs which must be brought under our interim program in the 2004 model year.

We will work with the applicant to
ensure that all other remedies available under this rule, e.g., use of banked or purchased credits, are exhausted before granting additional relief, and will limit the period of relief to one year. Note that
in our discussion of the credit deficit carryforward provision in section IV.B.4.d.vi, we indicate that we are not permitting small volume manufacturers to carry deficits forward until they have demonstrated compliance with the NOX averaging provisions for one year. This is to prevent small volume manufacturers, that have already
received additional time due to the waiver of the phase-in requirements, from gaining even more time to finally comply through the credit deficit carryforward provisions.

To avoid this provision creating a selfimplementing problem, by which the very existence of the hardship provision prompts small volume manufacturers to delay development, acquisition and application of new technology, we want to make clear that we expect this provision to be rarely used. Our final
rule contains numerous flexibilities for
all manufacturers and it waives the phase-in steps for small volume manufacturers, which effectively provides them more time. We expect small manufacturers, to prepare for the applicable implementation dates in today’s rule.

I. Compliance Monitoring and Enforcement

1. Application of EPA’s Compliance Assurance Program, CAP2000

The CAP2000 program (64 FR 23905, May 14, 1999) streamlines and simplifies the procedures for
certification of new vehicles and will also require manufacturers to test in-use vehicles to monitor compliance with
emission standards. The CAP2000 program was developed jointly with the
State of California and involved considerable input and support from manufacturers. As the name implies, it can be implemented as early as the 2000 model year.

We are finalizing our proposal that the Tier 2 and the interim requirements will be implemented subject to the requirements of the CAP2000 program. Certain CAP2000 requirements are being slightly modified to reflect changes to useful lives, standard structure and other aspects of the Tier 2 program, but we proposed no major changes to fundamental principles of the CAP2000 program, and we are not adding any major changes with today’s final rule.

Although we proposed changes to useful lives, we did not propose to amend the 50,000 mile minimum mileage used in manufacturer in-use verification testing or in-use confirmatory testing under the CAP2000program at this time. The CAP2000 inuse program is not yet implemented and we believe it is appropriate to allow manufacturers to gain experience with procuring and testing vehicles at the 50,000 mile level before making significant changes. However, where one vehicle from each in-use test group would have a minimum mileage of 75,000 miles under the CAP2000 program, we proposed and are finalizing, consistent with California, to


### 6796 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

change that figure to 90,000 miles for
Tier 2 vehicles.

We may, in our own in-use program, procure and test vehicles at mileages higher than 50,000 and pursue remedial actions (e.g., recalls) based on that data. We may also use that data as the basis to initiate a rulemaking to make changes in the CAP2000 in-use requirements, ifthe data indicate significant nonconformity at higher mileages.

We are finalizing certification test fuel specifications consistent with our final fuel sulfur requirements. Given the phase-in for low sulfur fuel we are finalizing in this rulemaking, we recognize that 2004 to 2007 vehicles (and vehicles certified in earlier model years to bank early NO X credits) may be exposed to higher sulfur levels early in
their lives. Because of this sulfur exposure, these vehicles could experience problems with OBD indicator light illuminations.

Consistent with our approach under the NLEV program, we will consider requests from manufacturers to permit OBD systems that function properly onlow sulfur fuel, but exhibit sulfurinduced passes when operated on higher sulfur fuel. For OBD systems that exhibit sulfur-induced indicator light illumination, we will consider requeststo modify such vehicles on a case-bycase basis.

2. Compliance Monitoring

We plan no new compliance monitoring activities or programs for
Tier 2 vehicles. These vehicles will be subject to the certification and manufacturer in-use testing provisions of the CAP2000 rule. Also, we expect to continue our own in-use testing program for exhaust and evaporative emissions. We will pursue remedial
actions when substantial numbers of properly maintained and used vehicles fail any standard in either in-use testing

program.

Consistent with our approach under NLEV we will consider requests, prior to manufacturer or EPA in-use testing to permit preconditioning procedures designed solely to remove the effects of high sulfur gasoline on vehicles produced through the 2007 model year.

We retain the right to conduct Selective Enforcement Auditing of new
vehicles at manufacturer’s facilities. In recent years, we have discontinued SEA testing of new LDVs and LDTs, because compliance rates were routinely at 100%. We recognize that the need for SEA testing may be reduced by the low mileage in-use testing requirements of the CAP2000 program. However, we expect to re-examine the need for SEA testing as standards tighten under the NLEV, interim, and Tier 2 programs.

We have established a data base to
record and track manufacturers’ compliance with NLEV requirements including the corporate average NMOG standards. We expect to monitor manufacturers’ compliance with the Tier 2 and interim corporate average

NO X standards in a similar fashion and also to monitor manufacturers’ phase-in percentages for Tier 2 vehicles.

3. Relaxed In-Use Standards for Vehicles Produced During the Phase-in
Period

The Tier 2 standards will be challenging for manufacturers to achieve, and some vehicles will pose more of a challenge than others. Not only will manufacturers be responsible for assuring that vehicles can meet the standards at the time of certification, they will also have to ensure that the vehicles comply when self-tested in-use under the provisions of the CAP2000 program, and when tested by EPA under its in-use (‘‘Recall’’) test program.

With any new technology, or even with new calibrations of existing technology, there are risks of in-use compliance problems that may notappear in the certification process. Inuse compliance concerns may discourage manufacturers from applying new technologies or new calibrations. Thus, we proposed and are finalizing,

relaxed in-use standards for those bins most likely to require the greatest applications of effort, to provide assurance to the manufacturers that they will not face recall if they exceed standards by a specified amount.

For the first two years after a test group meeting a new standard is introduced, that test group will be subject to more lenient in-use standards. These ‘‘in-use standards’’ will apply only to bin 5 and below, only for the pollutants indicated, and only for the first two model years that a test group

is certified under that bin. The in-use standards will not be applicable to any test group first certified to a new

standard after 2007 for LDV/LLDTs or

after 2009 for HLDTs.

The temporary in-use standards are

shown in Table V.A.–3 below.



### TABLE 

### V.A.–3.—I N



### - USE 

### C OMPLIANCE 

### STANDARDS 

### ( G

### /MI 

### )

[Certification standards shown for reference purposes]

Bin Durability period (miles) NOX In-use NOX certification NMOG
in-use NMOG certification

5 .. 50,000 0.05 n/a 0.075 5 .. 120,000 0.10 0.07 n/a 0.090 4 .. 120,000 0.06 0.04 n/a 0.070 3 .. 120,000 0.05 0.03 0.09 0.055 2 .. 120,000 0.03 0.02 0.02 0.010

Because we are concerned that diesel vehicles may require low sulfur fuel to comply with our interim requirements and that such fuel may not be widely

available until the 2006–2007 timeframe, we are providing in-use standards specifically for diesel vehicles

certified to bin 10 standards. These standards will be determined by multiplying the applicable NO X and PM certification standards by factors of 1.2 and 1.35, respectively. These multipliers can be used only for years during which bin 10 is viable, only for diesels and only for the pollutants

indicated.

We believe manufacturers should and

will strive to meet certification

standards for the full useful lives of the vehicles, but we recognize that the existence of such in-use standards poses some risk that a manufacturer might aim for the in-use standard in its design

efforts rather than the certification standard, and thus market less durable designs. We do not believe that risk to be significant. We believe that such risks are more than balanced by the gains that can result from earlier application of new technology or new calibration techniques that might occur in a scenario where in-use liability is slightly reduced. Further, we believe

that the in-use standards will be of short enough duration that any risks are

minimal.


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4. Enforcement of the Tier 2 and Interim Corporate Average NO X Standards

We are finalizing, as proposed, that manufacturers can either report that they meet the relevant corporate average

NO X standard in their annual reports to the Agency or they can show via the use
of NO X credits that they have offset any exceedance of the corporate average

NO X standard. Manufacturers will also have to report their NO X credit balances
or deficits.

The averaging, banking and trading program will be enforced through the certificate of conformity that the
manufacturer must obtain in order to introduce any regulated vehicles into
commerce. The certificate for each test group will require all vehicles to meet the applicable Tier 2 emission standards from the applicable bin of the Tier 2 program, and will be conditioned upon the manufacturer meeting the corporate average NO X standard within the required time frame. If a manufacturer fails to meet this condition, the vehicles causing the corporate average NO X exceedance will be considered to be not covered by the certificate of conformity for that engine family. A manufacturer will be subject to penalties on an
individual vehicle basis for sale of vehicles not covered by a certificate. These provisions will also apply to the interim corporate average standards.

As outlined in detail in the preamble to the final NLEV rule, EPA will review the manufacturer’s sales to designate the
vehicles that caused the exceedance of the corporate average NO X standard. We will designate as nonconforming those vehicles in those test groups with the highest certification emission values first, continuing until a number of vehicles equal to the calculated number of noncomplying vehicles as determined above is reached. In a test group where only a portion of vehicles are deemed nonconforming, we will determine the actual nonconforming vehicles by counting backwards from the last vehicle produced in that test group.
Manufacturers will be liable for penalties for each vehicle sold that is not covered by a certificate.

During phase in years, the certificates will also require manufacturers to meet the applicable phase-in requirements. Compliance with the phase-in requirements will be enforced in the same manner as for the corporate average NO X standard. For the optional phase-in requirement for HLDTs for model year 2004, manufacturers must declare in their application for certification whether they intend to comply with the interim requirementsfor all of their HLDTs and initiate phasein to the interim corporate average NOX standard in 2004 and receive the benefits of that phase-in (less stringent
NMOG standards for certain LDT2s and LDT4s). Compliance with this phase-in requirement and the fleet average NOX standard will be enforced just like compliance with any other average NOX standard and phase-in requirement of today’s program.

We will also condition certificates to enforce the requirements that
manufacturers not sell NO X credits that they have not generated. A
manufacturer that transfers NO X credits
it does not have will create an equivalent number of debits that it must offset by the reporting deadline for the same model year. Failure to cover these
debits with NO X credits by the reporting
deadline will be a violation of the
conditions under which EPA issued the certificate of conformity, and nonconforming vehicles will not be covered by the certificate. EPA will identify the nonconforming vehicles in
the same manner described above.

In the case of a trade that results in a negative credit balance that a manufacturer could not cover by the reporting deadline for the model year in which the trade occurred, we proposed, and are finalizing, to hold both the buyer and the seller liable. This is
consistent with other mobile source rules, except for the NLEV rule as
discussed below. We believe that holding both parties liable will induce the buyer to exercise diligence in assuring that the seller has or will be able to generate appropriate credits and will help to ensure that inappropriate
trades do not occur.

In the NLEV program we implemented a system in which only
the seller of credits would be liable. In the preamble to the final NLEV rule ( See 62 FR 31216), we explained that a multiple liability approach would be unnecessary in the context of the NLEV program given that the main benefit to a multiparty liability approach would be to ‘‘protect against a situation where one party sells invalid credits and then goes bankrupt, leaving no one liable for either penalties or compensation for the environmental harm.’’ Our preamble
stated further that EPA would not necessarily take the same approach for ‘‘other differently situated trading programs.’’

The NLEV program was implemented to be a relatively short duration program, during which time we could expect relative stability in the industry. Also, given that NLEV is a voluntary program of lower than mandated standards, we did not expect that the smallest manufacturers would opt in. These are the companies whose stability is most in jeopardy in a dynamic and very competitive worldwide business.

We currently believe that the Tier 2 program and its framework will remain for many years. We note that the program is not scheduled for complete phase-in for almost nine years after the publication of today’s rule. All manufacturers, large and small, will ultimately have to meet the Tier 2 standards. We cannot predict that in the
Tier 2 timeframe there will not be companies that leave the market or are divided between other companies in mergers and acquisitions. Thus we believe it is prudent to implement a program to provide inducements to the seller to assure the validity of any credits that it purchases or contracts for.

J. Addressing Environmentally Beneficial Technologies Not Recognized by Test Procedures

Compliance with the current and proposed EPA motor vehicle emission
standards is based on the emission performance of a vehicle over EPA’s prescribed test procedure. While this test procedure addresses many of the aspects of a vehicle’s impact on air quality, it does not address all such impacts. EPA is aware of two developing technologies which have potential to improve ozone-related air quality, but that would not do so over the current EPA test procedure.

The first example is a device that
removes ozone from the air as the vehicle is driven. A major producer of automotive catalysts, Englehard, has developed a catalytic coating for vehicle radiators (called PremAir) that converts ambient ozone to oxygen. ARB has been working with Englehard for some time to develop a procedure which would grant PremAir and other direct ozone reducing technologies a NMOG credit under its LEV I and LEV II programs. ARB issued on December 20, 1999 a Manufacturers Advisory Circular outlining procedures for establishing
such a NMOG credit.

Englehard submitted substantial comments to the Tier 2 NPRM, including ozone modeling results for five cities (Los Angeles, Houston, Atlanta, New York City, and Chicago). This ozone modeling compared the
ozone reductions from reduced exhaust
VOC and NO X emissions to that from using PremAir. As a result of this modeling, Englehard requested that EPA grant a typical PremAir system a NMOG

or NO X emission credit of 0.015 g/mi. This credit would be adjusted based the exact design and performance of the system and vehicle being certified.


### 6798 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

The second example is an insulated catalyst. The insulation retains heat for extended periods of time, increasing the catalyst temperature when the engine is started and reducing the time required for the catalyst to reach an operational temperature. This technology can reduce cold start emissions for engine off times (called soaks) of 24 hours or less. The vast majority of engine soaks in-use are less than 24 hours. However, EPA’s test procedure only tests emissions at two fairly extreme soak
times: 10 minutes and 12–36 hours. The
10 minute soak is so short that even an uninsulated catalyst is warm enough to quickly begin working upon restart. The 36 hour soak is beyond the practical limit of cost-effective insulating techniques. As a result of the Tier 2 NPRM, EPA received a number of inquiries from potential manufacturers of insulated catalysts, requesting further information about emission credits, test procedures and certification requirements.

EPA believes that both of these technologies, as well as other potential technologies, will reduce regulated emissions and/or ambient ozone levels,as long as they operate as designed inuse. EPA will work with the developers of such technologies to establish regulatory procedures to determine whether it is appropriate to grant emission credit for particular technologies. This process will involve the opportunity for public notice and

comment.

With regard to Englehard’s PremAir technology, EPA specifically requested comments on ARB’s proposed approach to determining an NMOG credit and
received no adverse comment on granting this type of technology a VOC emission credit. Thus, EPA is promulgating today procedures very similar to ARB’s for certifying such technologies and determining the appropriate VOC emission credit. The only difference between EPA’s and ARB’s procedures involve assessing the
effectiveness of VOC emission reductions and ozone reducing devices
in areas outside of California.

In summary, the ozone reductions associated by both the ozone reducing technology, such as PremAir, and
exhaust VOC emission reductions will be estimated using urban airshed modeling, using up-to-date chemical and meteorological simulation techniques. Four local areas shall be modeled: New York City, Chicago,
Atlanta and Houston. The ozone episodes to be modeled shall be those selected by the states for use in their
most recent ozone SIPs. Emissions shall be projected for calendar year 2007. Baseline emissions will include the
benefits of the Tier 2 and sulfur standards being promulgated today, as
well as all other emission controls assumed in EPA’s ozone modeling of
the benefits of the Tier 2 and sulfur
standards described above. The ozone
benefit of VOC emission reductions will be modeled by assuming that Tier 2 LDVs and LDTs meet a 0.055 g/mi
exhaust NMOG standard instead of a 0.09 g/mi NMOG standard. The relationship between changes in exhaust
NMOG emission standards and in-use VOC emissions shall be determined by modeling LDV+LDT emission in 2030 assuming that all Tier 2 vehicles meet a 0.055 g/mi exhaust NMOG standard instead of a 0.09 g/mi NMOG standard. All emission modeling shall utilize the updated Tier 2 emission model developed by EPA as part of this rule, or MOBILE6, once it is available. The
measure of ozone to be used in calculating VOC emission equivalency will be the peak one-hour ozone level anywhere in the modeled region on the day when ozone is at its highest. The NMOG credit will be determined by averaging the NMOG credit determined
in each of the four local areas.

Simulation of the benefits of the direct ozone reducing device will assume that ozone levels immediately around the roadway will be 40% less than that existing in the broader grid. The performance aspects of the direct ozone reducing device can be simulated by any reasonable values, since the appropriate NMOG credit for any specific application of this technology will be scaled to the performance of the specific application.

The manufacturer wishing to obtain
an NMOG credit for use of this technology must demonstrate its effectiveness to EPA as part of the certification process. This will involve demonstrating the air flow through the device, its ozone destruction capability under conditions analogous to those photochemically modeled, the durability of this capability over the
useful life of the vehicle and the method to be used to diagnose its effectiveness

in-use.

Regarding the insulated catalyst technology, less information has been received to date on its performance. We are not promulgating regulations for determining the appropriate credit for such technology today. However, when we were developing our SFTP standards, EPA developed a methodology to assess the emission benefits of insulated catalysts or other techniques which reduced emissions
after the vehicle soaks between 10 minutes and 12–36 hours. Thus, EPA expects to use this methodology as a starting point in assessing the benefit of insulated catalysts and will continue to assess development of options in this area. Because an insulated catalyst operates essentially like a typical catalyst, we do not expect that the test procedures for its certification would differ from those applicable to typical Tier 2 vehicles. The primary difference
will be an assessment of its effectiveness relative to conventional catalyst technology over a range of vehicle soak
times between 10 minutes and 36 hours. Then, it will be necessary to estimate the average effectiveness in-use relativeto conventional technology using the inuse frequency of vehicle soak times.

K. Adverse Effects of System Leaks

The standards set forth in today’s final rule are very stringent. They require extremely tight control of air/ fuel ratios and also tight control of the inputs to the catalyst(s). A sealed exhaust system is crucial to the proper operation and emission control of
current vehicles and even more so to the expected Tier 2 vehicles. Because a given point in the exhaust system intermittently sees negative pressure, exhaust leaks can permit air to enter the exhaust system. Even tiny amounts of air entering this way can have large impacts on the output of the oxygen sensor. If the output of the oxygen sensor is affected, then the exhaust output of the cylinders will be affected. Consequently, an exhaust leak can lead
to both excess NO X and NMOG emissions. Air entering through exhaust leaks can also impact the NOX conversion efficiency of catalysts.

In the preamble to the NPRM, we expressed our concerns about the impact of small exhaust leaks andrequested comment on design or onboard monitoring measures we could finalize to ensure that exhaust systems
were manufactured and installed in such a way that leaks are prevented. We
also asked for comment on whether we should implement a provision that would require manufacturers to demonstrate through engineering analysis or design that the possibilities
of exhaust leaks have been addressed.

Manufacturers indicated in their comments that they believe addressing exhaust leaks is unnecessary. We
believe otherwise. Data we have seen suggest that very large emission effects can occur due to very small leaks. Consequently, we are finalizing a provision in today’s rule that will require, as part of the certification process, for manufacturers to indicate that they have conducted an engineering analysis of the exhaust system. This


### 6799 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

125 40 CFR Part 80, subpart F. analysis must cover the entire exhaust system, including air injection systems, from the engine block exhaust manifold gasket surface to a point beyond the last catalyst or oxygen sensor. This analysis

must determine whether the exhaust system has been designed to facilitate leak-free assembly, installation, repair and operation for the full useful life of

the vehicle.

With regard to the concept of ‘‘facilitating leak-free repair’’, we intend

that manufacturers should ascertain that the exhaust system can be removed in a dealership or repair shop for repairs to the exhaust system itself or to other components of the vehicle and be able
to be reassembled and reinstalled in a leak free manner using commonly
available tools. It is not our intention that the concept of ‘‘facilitating leak-free repair’’ apply to situations of gross misuse, tampering or serious vehicle damage.

L. The Future Development of Advanced Technology and the Role of Fuels

The EPA staff will continue to assess the emission control potential of vehicles powered by technologies such
as lean-burn and/or fuel-efficient technologies, including diesel engines equipped with advanced aftertreatment systems, gasoline direct injection engines, and other technologies that show promise for significant advances in fuel economy and meeting the Tier 2 standards in the post-2004 time frame. In this assessment, we will maintain a ‘‘systems’’ perspective, considering the progress of advanced vehicle technologies in the context of the role that sulfur in fuels plays in enabling the
introduction of these advanced technologies or maximizing their
effectiveness.

M. Miscellaneous Provisions

We are finalizing, as proposed, to continue existing emission standards from Tier 1 and NLEV that apply to cold CO, certification short testing, refueling, running loss, and highway NO X . We are discontinuing, as proposed, the 50 degree (F) standards and testing included in the NLEV program. The 50 degree standards are a part of the NLEV program because that national program adopted California requirements virtually in their entirety. These standards had not previously been part of any federal program. We are also discontinuing idle CO standards for LDTs, based upon comment. These standards are adequately covered by the
certification short test standards. VI. Gasoline Sulfur Program Compliance and Enforcement

Provisions

A. Overview

The gasoline sulfur program promulgated today has many of the
same features as the reformulated gasoline/conventional gasoline (RFG/ CG) program, including refinery averaging, refinery and downstream level caps, and the generation and use
of credits. These features raise similar compliance issues for both programs. As a result, the enforcement mechanisms of the gasoline sulfur rule generally track those of the RFG/CG rule, where applicable. Because low sulfur gasoline is necessary to avoid significant impairment of Tier 2 motor vehicle emissions technology, we believe
measures are needed to assure that gasoline meets the standards promulgated in today’s rule at the time the gasoline leaves the refinery gate or is imported, and to assure that the quality of the gasoline is maintained downstream of the refinery.

More specifically, today’s rule includes the following provisions:

• Refiners and importers must test each batch of gasoline produced or imported for sulfur content and maintain testing records and retain test samples;

• Refiners and importers must submit reports regarding compliance with the average standards and credit provisions;

• Attest procedures 125 similar to
those of the RFG/CG rule will be applied to the sulfur standards and credit provisions;

• Refiners and importers are prohibited from using, selling or purchasing invalid sulfur credits, and are required to adjust compliance
calculations if invalid credits have been used, sold or purchased;

• Small foreign refiners subject to the
small refiner standards described in section IV.C. above must comply with the rule’s small refiner compliance requirements and other requirements to ensure the separation of such foreign gasoline from all other gasoline to the U.S. port of entry; any foreign refiners participating in the early credit generation program must also meet certain provisions concerning credit generation, including reporting and recordkeeping;

• All regulated parties in the gasoline distribution system who are downstream from the refiner or importer must comply with downstream sulfur cap standards; • Regulated parties are subject to presumptive liability for violations at a party’s own facility and for violations at
other facilities that could have been caused by the regulated party; branded refiners are subject to liability for violations occurring at branded
facilities.

• Refiners and distributors may implement downstream quality assurance testing to assure compliance
and to establish an element of defense against presumptive liability.

As in other fuels programs, the sulfur standards apply to all motor vehicle fuel that meets the definition of gasoline, except for aviation fuel and racing gasoline, as was proposed in the NPRM. See 40 CFR 80.2(c). Gasoline sulfur standards apply, however, to gasoline that is ultimately used in nonroad equipment or marine engines.

As we noted in the NPRM, we are aware there are certain fuels, such as aviation fuel and racing fuel, that are generally segregated from gasoline throughout the distribution system. Where such fuels are segregated from motor vehicle gasoline and not made available for use in motor vehicles, the fuel is not subject to sulfur rule standards. However, if such fuels are not segregated throughout the distribution system, but are used as motor vehicle gasoline or are commingled with motor vehicle gasoline, then any person who introduces such fuels into the gasoline distribution system is a refiner, subject to all the refiner requirements of today’s regulations, including registration, reporting, testing and meeting the national refiner average and cap standards for the volume of gasoline that person added to the distribution system. Today’s rule adopts the provisions concerning fuel used for racing vehicles as proposed.

One commenter suggested that racing gasoline or aviation gas should be
allowed to be used as motor vehicle gasoline by downstream parties so long as the racing gasoline or aviation gas does not exceed the applicable downstream cap standard. We disagree. Racing gas that meets the applicable downstream sulfur cap would nevertheless not be subject to the refinery gate cap or averaging standards, and may not meet such standards. Allowing such fuels to be distributed for
motor vehicle use would thus
circumvent the intent of the rule.

The rule promulgated today clarifies the definition of ‘‘refinery’’ at 40 CFR 80.2(h), as was proposed in the NPRM.
We received no comments on this clarifying change. Specifically, section 80.2(h) now provides that ‘‘refinery’’


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126 The term ‘‘oxygenate blenders’’ includes

‘‘ethanol elnders.’’ 127 Reformulated Gasoline and Anti-dumping Questions and Answers, (11/12/96); Proposed Rule for Modifications to Standards and Requirements for Reformulated and Conventional Gasoline; 62 FR 37337 et seq. (July 11, 1997). 128 62 FR 37337 et seq. (July 11, 1997) (proposed 40 CFR 80.84). means any facility, including a plant, tanker truck or vessel where gasoline or diesel fuel is produced, including any facility at which blendstocks are combined to produce gasoline or diesel fuel, or at which blendstock is added to gasoline or diesel fuel. This is consistent with all current EPA fuels rules, interpretations, policies and question
and answer documents.

Oxygenate Blenders

In the NPRM we proposed that oxygenate blenders 126 would not be subject to the refiner sulfur standard like other blenders, because we felt it unlikely that oxygenates will have
sulfur levels that will raise the sulfur content of the gasoline. This approach also was proposed because gasoline is the denaturant normally used to produce denatured ethanol. However,
we received comments that denatured ethanol may contain as much as 50 ppm sulfur, which could result in significant
increases in sulfur content from ethanol blending alone.

While it is true that some of today’s gasoline has a sulfur content as high as 1,000 ppm which if used as an ethanol denaturant results in ethanol having a sulfur content of 50 ppm, the average sulfur content of gasoline is about 300 ppm which if used as an ethanol
denaturant results in ethanol with a sulfur content of 15 ppm. In addition, when the gasoline sulfur standards being promulgated today are in effect, the average sulfur levels of gasoline will be significantly reduced, which will
further reduce the sulfur content of denatured ethanol to very low levels. For this reason, we are finalizing the regulation as proposed that oxygenate blenders are not subject to refiner sulfur
standards.

However, if gasoline blendstock instead of finished gasoline is used as a denaturant for ethanol the oxygenate
blender who adds the ethanol would become a ‘‘refiner,’’ who is required to demonstrate compliance with the sulfur
standards for the denatured ethanol added to gasoline. This is because the oxygenate blender would be adding a blendstock along with the ethanol, which subjects the blendstock blender to refiner standards and requirements. Moreover, if the blendstock has a high
sulfur content the denatured ethanol could have a sulfur content greater than 30 ppm, or even greater than 80 ppm, which could make compliance by such a ‘‘refiner’’ difficult or impossible. In addition, as discussed above, in certain cases ethanol is included in the refinery compliance calculations of the refiner who produced the gasoline or RBOB
with which the ethanol is blended.
Refiners assume this ethanol has no sulfur content, an assumption that could be incorrect if high sulfur blendstock is
used as the denaturant.

For these reasons we believe it is important that ethanol blenders use
denatured ethanol with a sulfur content of 30 ppm or less, which would occur if the current practice of using finished gasoline as ethanol denaturant continues. In order to ensure this result, the regulations include a provision that prohibits ethanol blenders from using
denatured ethanol with a sulfur content greater than 30 ppm. We believe ethanol blenders can comply with this requirement through commercial arrangements with their ethanol suppliers, that specify the maximum
sulfur content of denatured ethanol. In addition, ethanol blenders can assure compliance with this requirement by testing to determine the sulfur content
of denatured ethanol received.

Gasoline Treated as Blendstock (GTAB)

One commenter suggested that the Agency policy under the RFG/CG rule that allows certain imported gasoline tobe treated as a blendstock by importerrefiners should be applied to today’s rule. The GTAB policy was originally issued in the RFG Question and Answer document, and was subsequently published as part of a proposed RFG rulemaking in 1997. 127 We intend to
address GTAB issues in that RFG rulemaking, including issues regarding compliance with today’s rule.

Transmix

We are aware that when gasoline meeting the requirements finalized in today’s rule is transported through pipelines, there will be some situations where adjacent distillate product in the pipeline will mix with a portion of the gasoline to create an interface product, commonly referred to as transmix. This transmix may not be blended into the diesel fuel because the gasoline in the transmix may result in diesel fuel performance problems. Historically, this type of transmix product has either been blended into the gasoline, in limited concentrations, or the transmix has been separated into its gasoline and distillate components at a reprocessing plant. However, the practice of blending the transmix into gasoline may result in
violations of the downstream standards for RFG, and such blending could violate the downstream sulfur caps finalized in today’s rule, because many distillates have a very high sulfur content. Therefore, we believe regulatory provisions are needed to
resolve these issues. We have not addressed transmix issues in today’s rule because we have already proposed regulations regarding transmix blending and processing in another rulemaking. 128 We plan to address transmix issues, including issues regarding compliance with today’s rule, in that rulemaking, which we plan to
finalize in the near future.

Inability To Produce Conforming Gasoline in Extraordinary

Circumstances

Several commenters suggested the rule should include a provision, similar to the RFG rule provision at 40 CFR 80.73, to address situations where, due to extraordinary circumstances, a refiner or importer cannot produce or distribute conforming gasoline. Section 80.73 applies to refiners, importers and oxygenate blenders. Today’s rule has adopted the provisions of section 80.73 for RFG and CG, for importers and refiners, but not for oxygenate blenders. This is because the gasoline sulfur program does not include provisions that would be expected to require oxygenate blender relief.

In the remainder of this section we discuss enforcement issues regarding today’s rule that are not covered in this Overview or in section IV.C., above.

B. Requirements for Foreign Refiners and Importers

In the NPRM we proposed that standards for gasoline produced by foreign refineries that are not subject to small refiner individual refinery standards would be met by the importer. Standards for gasoline produced by a foreign refinery subject to an individual sulfur rule standard would be met by the foreign refinery, with certain limited exceptions as provided in the foreign refinery provisions. The rule promulgated today adopts the provisions as proposed, except for several changes aimed at clarifying the proposed requirements, changes relating to the temporary relief provision, and changes relating to foreign refiners’ participation in the early credit program. These provisions are very similar to the foreign refinery provisions
of the RFG/CG rule.


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129 40 CFR 80.94. 130 Small refiner and temporary refiner hardship individual refinery standards sunset January 1, 2008, except for any small refineries that receive a hardship extension not to exceed two years. 1. Requirements for Foreign Refiners With Individual Refinery Sulfur
Standards or Credit Generation
Baselines

Under the RFG/CG rule, EPA promulgated regulations 129 addressing the establishment and implementation of individual baselines for CG produced by certain foreign refiners. The purpose of these regulations is to ensure the compliance of gasoline supplied from foreign refineries with individual compliance baselines. It includes comprehensive controls, requirements
and enforcement mechanisms to monitor the movement of gasoline from the foreign refinery to the U.S., to monitor gasoline quality and to provide for enforcement as necessary.

In the NPRM, we proposed similar requirements for compliance with the applicable sulfur standards that would apply to any foreign refiner who
demonstrates that it meets the sulfur program’s small refiner criteria. We proposed that foreign refinery baselines would be based on annual average sulfur levels and the volume of gasoline imported to the U.S. during the same baseline period as would be applicable to domestic small refiners. In today’s final rule we have also adopted provisions for foreign refiners to establish baselines to participate in the early credit generation program, and to request temporary relief. Any foreign refiner who obtains a foreign refinery gasoline sulfur baseline would be subject to the same requirements as
domestic refiners with individual refinery baselines under today’s rule. Additionally, provisions similar to the provisions at 40 CFR 80.94 would apply, which include:

• Segregating gasoline produced at the small refinery until it reaches the U.S.;

• Refinery registration;

• Controls on product designation;

• Load port and port of entry testing;

• Attest requirements; and

• Requirements regarding bonds and sovereign immunity.

The rationale for these enforcement provisions is discussed more fully in the Agency’s preamble to the final RFG/CG foreign refineries rule (62 FR 45533 (Aug. 28, 1997)).

Several commenters suggested that the rule should have even stronger enforcement provisions concerning foreign refiners, including criminal provisions against foreign individuals who violate the requirements of the rule. While we agree that the rule’s enforcement provisions pertaining to foreign refiners must be effective, we believe the proposed enforcement provisions are sufficient, and that attempts to further strengthen them would not significantly increase their overall effectiveness. Today’s rule imposes various requirements on foreign refiners not required of domestic refiners, as noted above, which we believe are more effective for ensuring environmental compliance than criminal provisions would be for foreign individuals, in light of the potential difficulties of enforcing sanctions against foreign individuals. EPA’s experience to date with the similar RFG/ CG requirements under section 80.94 of
the RFG/CG rule does not indicate the provisions are inadequate.

Therefore, today’s rule generally retains these provisions as proposed.
The final rule makes several technical changes, including changes regarding baselines for foreign refiners, to be consistent with the requirements for
domestic small refiners and refiners generating early credits finalized in today’s rule. The rule’s foreign refiner enforcement provisions now also apply to foreign refiners participating in the early credits program, and to the use of credits by foreign small refiners.

One commenter stated that the language of the proposed § 80.410(n) would be too broad in that prohibiting any ‘‘person’’ from combining certifiedsmall foreign refiner gasoline with noncertified small foreign refiner gasoline or with certified small foreign refinery gasoline produced at a different refinery would prohibit even retail level commingling of such products. This was not intended and today’s rule clarifies that such commingling can occur subsequent to importation.

Under the proposal, when the small refiner standards sunset (and additionally under today’s rule, when the temporary refiner relief provisions sunset), 130 all gasoline would be subject to a single national averaged standard and one national refinery level cap. Thereafter, standards for all imported gasoline would be met by U.S. importers. We have retained this provision as proposed. With a single national average standard and cap standard, gasoline sulfur content can most readily be monitored at the U.S. importer level, since there will no longer be a special class of gasoline with
different standards that would need to
be monitored. 2. Requirements for Truck Importers

Today’s final rule adopts the proposed requirement for importers to sample and test each batch of gasoline imported. However, as noted in the preamble to the NPRM, for parties that import gasoline into the U.S. by truck, the every-batch testing requirement would include testing the gasoline in each truck compartment, or if the gasoline is homogeneous, testing the gasoline in the truck.

In the NPRM we recognized that this every-batch testing requirement may not be feasible for truckers hauling many small loads of gasoline, and we therefore proposed a limited alternative approach for truck importers in lieu of every-batch testing. The proposed alternative approach is based on the importer meeting the 30 ppm sulfur standard on a per-gallon basis. Under this alternative approach, the importer would be allowed to rely on the sulfur results based on sampling and testing conducted by the operator of the foreign truck loading terminal. Because, in most cases, the terminal operator will not be subject to United States laws, we also proposed safeguards intended to ensure that the gasoline in fact meets the applicable standard. This includes the requirement that the importer conduct a quality assurance sampling and testing program independent from the sampling and testing conducted by the terminal. Under this approach the reporting requirements would be minimized since no averaging would be required. The environmental consequences of this approach would be neutral, because by meeting the 30 ppm sulfur standard on an every-gallon basis the standard also would be met on average.

One commenter stated that the 30 ppm per-gallon standard would be difficult for truck importers to meet due to the fact that Canadian terminals may not always have gasoline with a sulfur content no greater than 30 ppm. The commenter suggested that truck importers be allowed to rely on testing conducted by the foreign gasoline terminal, as discussed above, to meet the average and cap standards like other importers.

We agree that truck importers may have difficulty obtaining gasoline that meets the 30 ppm sulfur standard on a per-gallon basis. Under Canadian regulations, Canadian refiners will be subject to a 150 ppm average standard and a 300 ppm cap in 2004, and in 2005 Canadian refiners will be subject to a 30 ppm average standard and an 80 ppm


### 6802 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

131 Vol. 133 23/6/99 C. Gaz. II, 23 June 99 (pp.

1469 et seq. ) 132 In 2004, a 120 ppm cap; In 2005 and beyond, a 30 ppm cap. See Table IV.C.–1.

133 In 2004, a 120 ppm average standard and a 300 ppm cap; In 2005, a 30 ppm average standard, a corporate pool average no greater than 90 ppm, and a 300 ppm cap; In 2006 and beyond, a 30 ppm average standard and a 80 ppm cap. See Table

IV.C.–1. cap. 131 This means that truck importers
should be able to meet the standards applicable to other importers, including the ultimate average standard and cap standard under today’s rule (30 ppm average and 80 ppm cap), without greatdifficulty. However, meeting a pergallon cap of 30 ppm might be difficult since the sulfur content of gasoline in the storage tanks of Canadian terminals, like those of U.S. terminals, will likely exceed 30 ppm at times, even after the 30/80 standards are implemented. We
have concluded that we can address this concern by providing additional flexibility to truck importers, and still assure compliance.

While today’s rule retains the proposed alternative, with some modifications, it also provides a second alternative approach. Under this second approach, truckers are allowed to meet the national average and cap applicable to other importers, and rely on testing conducted by the foreign gasoline terminal so long as all the other requirements applicable to the proposed alternative approach are complied with. In addition, truckers using this second alternative approach will be subject to more extensive reporting than required for the proposed alternative, since the importer will have to demonstrate compliance with the annual average sulfur standard applicable to other importers.

One commenter urged that truckers should be subject only to the national downstream cap. We cannot agree to this approach as it is not environmentally neutral relative to the
national standards in effect for other importers and refiners. If truck importers were required to meet only the downstream cap, sulfur levels for their imported gasoline could be substantially higher than for other importers, which could have a
detrimental environmental

consequence.

One commenter stated that the 30 ppm per-gallon standard for truck importers should not go into effect until the 30 ppm standard becomes the national average standard for refineries and other importers. We agree. Under today’s rule, the per-gallon standards applicable to truck importers under the proposed alternative will be the same sulfur level as the sulfur average standard that applies to other importers (in 2004 there is no average standard; however, truck importers using this alternative compliance approach must meet the corporate pool standard on a per-gallon basis). 132 Under the second alternative approach, the truck importer will be subject to the same average standard and cap standard applicable to other importers. 133

Similar provisions as provided above apply to truck importers for gasoline subject to the geographic phase-in area (GPA) standards (see section IV.C. of this preamble for a discussion of GPA standards). However, because of the small volumes of truck-imported gasoline, and the consequent difficulty in meeting corporate pool averages for a trucker who imports gasoline into both the GPA and areas outside the GPA, today’s rule requires that for truck importers using the averaging option, the corporate pool average does not have to be met. The 150 ppm average standard and the 300 ppm cap standard apply to gasoline imported by truck into the GPA in 2004 through 2006. For truck importers meeting the per-gallon standard option for gasoline imported into the GPA, the per-gallon standards are 150 ppm for 2004 through 2006.

Truck Import of Foreign Small Refiner
Gasoline

The NPRM addressed issues associated with gasoline produced by a foreign small refinery with an
individual baseline and certified as subject to the refinery’s individual interim standard (S–FRGAS), and imported by truck. The proposed requirements for S–FRGAS included segregating the gasoline from all other gasoline from the refinery gate to the U.S., so that compliance with standards can be tracked. For ordinary, non-truck importers, each batch of certified S– FRGAS must be tested at the load port and port of entry. Today’s rule finalizes these proposed requirements for S–

FRGAS.

However, in the case of gasoline imported by truck, the NPRM acknowledged that the testing and other procedures proposed for certified S– FRGAS may not be feasible. As a result, we proposed an alternative to the requirement for testing every truckload of imported certified S–FRGAS, and to other importer requirements. This alternative approach includes a requirement that small foreign refiners producing any S–FRGAS that will be imported by truck submit a petition to EPA that includes a plan which is designed to ensure that certified S– FRGAS remains segregated from all other gasoline from the refinery to the U.S. Rather than specifying the precise requirements of such a plan in the regulations, we proposed to allow the refiner to develop its own procedures for ensuring that S–FRGAS remains segregated. However, the plan must contain certain elements, such as product transfer documents which identify the origin of the gasoline and prohibit its commingling with any product other than certified S–FRGAS from that refinery.

This approach also requires the refiner of such truck-imported gasoline to receive and maintain all such product shipment documents, including U.S. import documents, for five years and review these to ensure that segregation is maintained until reaching the U.S. To ensure that refiners conduct this review, we proposed to require the refiner’s plan to include attest audit procedures to be conducted annually by an independent third party.

We received no comments on this proposal for ensuring the integrity of S– FRGAS imported by truck. Today’s final rule adopts the petitioning provision to permit alternative segregation procedures for S–FRGAS imported by truck as proposed since we continue to believe that it will provide flexibility to foreign refiners and to importers and will adequately assure enforceability.

C. What Standards and Requirements Apply Downstream?

We proposed per-gallon cap standards that would apply to all parties in the distribution system downstream of the refinery and importer level, including pipelines, terminals, oxygenate blenders, distributors, carriers, retailers and wholesale purchaser-consumers. We believe that downstream cap standards and compliance monitoring
based on downstream standards are
needed to ensure that the sulfur level of gasoline remains below the cap level when dispensed for use in motor vehicles, to avoid adverse emissions consequences that would be caused by the use of gasoline having a sulfur content above the cap level. The following discussion addresses downstream standards generally,
downstream standards and requirements for gasoline produced by refineries subject to standards under § 80.240 and 80.270, and downstream standards and requirements for gasoline produced or imported for the geographic phase-in area (GPA).


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134 ASTM standard method D 2622–98, entitled

‘Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry.’’ Determination of Downstream Cap
Standards

We proposed that the downstream
standards would be more lenient than the refinery-level cap standards so that refiners and importers can produce gasoline that equals the refinery-level cap standard. We did so because it has been EPA’s experience that if a refiner produces gasoline that equals, or almost equals a standard, that gasoline may be
shown to violate the standard when subsequently tested at a location downstream of the refinery due to testing variability. As a result, parties downstream of the refinery (primarily pipelines) set commercial specifications for the quality of the gasoline they will accept that are more stringent than the standard that applies to the downstream party. This, in effect, forces refiners to produce gasoline that is ‘‘cleaner’’ than the refinery-level standard.

In other fuels programs (for example, the benzene per-gallon standard for RFG) we resolved this concern by announcing enforcement tolerances for fuels standards that apply downstream of the refinery-level, thereby reducing the need for pipelines to set specifications more stringent than the refinery level standards. We believe that having more lenient downstream
standards will have the same effect as
enforcement tolerances.

In the NPRM we proposed that the values of the downstream cap standards would reflect the testing variability that could reasonably be expected when different laboratories test gasoline for sulfur content; that is, lab-to-lab variability, or reproducibility. Industry commenters supported this approach, and today’s rule adopts this approach. For gasoline subject to the 80 ppm refinery-level sulfur cap, the
downstream maximum standard is 95 ppm. This difference reflects the reproducibility established by the American Society for Testing and Materials (ASTM). 134 For gasoline subject to refinery-level sulfur caps higher than 80 ppm, which will be the case for gasoline produced before 2006 and for gasoline produced by certain small refineries through 2007, the downstream cap is similarly established by using ASTM reproducibility data. The national downstream cap is 378 in 2004, when the refinery level cap can be as high as 350 ppm. The national downstream cap in 326 in 2005, when the refinery level cap is 300. Because these downstream caps are based on sulfur test reproducibility, we
intend to amend the rule in the future if improvements in test precision are made for the designated method. We may also consider amending the rule to make some other method the designated method if a more precise method is
available in the future.

The Proposed Downstream Standards Compliance Scheme

Under the proposal, if gasoline produced by a small refiner with a less stringent cap standard is mixed in the distribution system with gasoline subject to the national cap standard, the entire mixture would then be subject to the higher cap standard, even though most of the gasoline, at the refinery level, would be subject to the more stringent national cap standard. We proposed that during the period that small refinery individual standards are in effect, for gasoline that is comprised, in whole or in part, of small refiner gasoline with a higher sulfur cap standard than the national cap standard, product transfer documents (PTDs) would specify that the gasoline is small refiner gasoline and the level of the downstream cap applicable to the gasoline.

The purpose of the proposed provisions was to make it possible to determine the standard that applies to any gasoline downstream of the refinery. If the gasoline contains no small refiner gasoline, the downstream
standard would be based on the national cap. If the gasoline is comprised, in whole or in part, of small refiner gasoline subject to a less stringent cap standard, the downstream standard would be based on this less stringent cap standard. As gasoline is mixed and remixed in the fungible distribution system, the percentage of gasoline that is small refinery gasoline will progressively diminish until the fungibly mixed gasoline meets the national downstream cap. Therefore, we proposed in the NPRM that a downstream party may no longer classify gasoline as containing small refiner gasoline if a test result shows the sulfur content of the gasoline is below the applicable national (i.e., not small refiner) downstream cap.

Several commenters suggested that this tracking scheme would be
unworkable. Some of these comments
were based on the belief that the proposal intended to require segregation of the small refiner gasoline through the distribution system. The proposal was not intended to require that small refiner gasoline must be segregated, and under today’s final rule there is no requirement that small refiner gasoline must be segregated from gasoline produced by other refiners. Some commenters also believed that testing by downstream parties would be required under the proposed rule. These
commenters were concerned that a downstream testing requirement could be costly and could delay distribution of gasoline. This latter point is addressed
later in this discussion. Some commenters stated that the proposed PTD provisions of the downstream enforcement scheme were too complex
and that some means other than changing PTD designations should be found to track small refiner gasoline.

Other commenters, including
automobile manufacturer trade associations, stated they believed that EPA enforcement and testing downstream of the refinery is necessary to assure that gasoline complies with standards at the retail gasoline pump.

We have carefully considered the
comments and we have concluded that the tracking scheme as proposed would not be effective because most pipeline shipments are expected to include some small refiner gasoline (although the amount of small refiner gasoline may comprise less than 1% of the shipment) and therefore, most of the gasoline in the nation might be classified as small refiner gasoline, even though only a small fraction of the supply will actually be small refiner gasoline. Therefore, a downstream cap much less stringent than the national downstream cap would attach to most gasoline produced to meet the national refinery standards, and the scheme would not be effective in monitoring whether the quality of most gasoline is maintained after it enters the gasoline distribution system.

The proposed scheme could lead to other unintended results. The gasolines contained in a fungible mixture in the distribution system may not be fully mixed and homogenous. As a result, a distinct, unmixed, portion of gasoline within a fungible mixture could be small refiner gasoline with a sulfur
content above the national downstream cap, while other parts of the fungible
mixture would meet the national downstream cap. This is especially true for fungible mixtures in pipelines and could also be true for gasoline in storage tanks. If a test result for a sample collected from part of such a fungible mixture in a pipeline shows compliance with the national downstream cap, under the proposed rule the entire mixture would become subject to the national downstream cap, and the pipeline PTDs could not classify the gasoline as small refiner gasoline. Thus,


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135 For example, most pipeline shipments are expected to contain small refiner gasoline in the two U.S. pipelines that carry the highest volume of gasoline. However, in most shipments the small refiner gasoline is expected to account for substantially less than 5% of the total volume of gasoline in the shipment.

136 For purposes of this discussion, ‘‘small refiner gasolne’’ includes any gasoline from a refiner to whom EPA grants relief based on a showing of extreme hardship.

137 See section IV.C. of this preamble for refiner/ importer standards and the discussion below regarding downstream compliance and enforcement provisions. under the proposal, parties downstream of the pipeline could be subject to liability because they might receive small refiner gasoline not meeting the national standard even where a pipeline PTD does not represent that the gasoline is small refiner gasoline. That was not intended by the proposal.

Because of these difficulties, we concluded that the proposed scheme
must be modified to address these concerns, in order for there to be
effective enforcement of the
downstream standards. We are concerned that the quality of gasoline
will be affected downstream of the refinery. Gasoline may be contaminated with high sulfur blendstocks or other high sulfur products such as distillates after it leaves the refinery gate. There is likely to be an economic incentive for some downstream parties to sell or use gasoline or blendstocks that have a higher sulfur content than the national downstream standard. The inability to monitor downstream compliance would result in environmental degradation that is not intended by the rule, and in an inability to assure a level playing field for all parties in the gasoline distribution industry.

Tracking Gasoline Downstream of the Refinery

We believe that an effective downstream compliance and enforcement scheme is necessary in
order to achieve the full emissions reduction benefits of the rule. Today’s rule modifies the proposed tracking scheme so that compliance with the program can be monitored.

Under today’s rule, all gasoline downstream of the refiner or importer is subject to the national downstream
standard unless a different downstream standard, based on the highest sulfur content of any small refiner/temporary refiner relief gasoline in the gasoline mixture (as determined by the small refiners’ batch testing), is supported by PTDs and a test result confirming the presence of small refiner/temporary refiner relief gasoline. The test result must be for gasoline sampled from the downstream facility classifying the gasoline as small refiner gasoline, unless the facility is a trucker, retailer or wholesale purchaser-consumer. We have concluded that this requirement is necessary to monitor compliance with the downstream standards during the period that small refiner/temporary refiner relief standards are in effect, because the vast majority of the gasoline transported by pipelines will be gasoline produced to comply with the national cap, 135 even though most of those pipeline shipments will be classified as small refiner gasoline. 136

We believe that the ability to track small refiner gasoline is made even more important due to the geographic phase-in area (GPA) gasoline provisions finalized today. 137 GPA gasoline is subject to less stringent refiner/importer standards than gasoline produced for use in other parts of the country. Therefore, its use is limited to the GPA states. However, it may be produced or imported at any location in the country before it is transported for use in the GPA. EPA would have little ability to assure GPA-designated gasoline is only being used in the GPA if it cannot determine if gasoline at a downstream
location outside the GPA that exceedsthe applicable downstream cap for nonsmall refiner gasoline, is in fact small refiner gasoline or if it may include gasoline that was designated for use in
the GPA but has been diverted for use elsewhere. The tracking requirements for small refiner gasoline will help us to
make that determination.

The only parties required to perform testing in order to demonstrate that a shipment, or tank, of gasoline contains small refiner gasoline are gasoline pipelines and terminals. Where a terminal properly classifies gasoline in its storage tank as small refiner gasoline, and subsequently receives a load of gasoline into that tank, it may not continue to classify the gasoline as small refiner gasoline unless the tank is sampled, and a test demonstrates that
the tank still contains small refiner gasoline and the gasoline sulfur content exceeds the national refinery level cap.
In 2004 the test result would have to exceed 350 ppm; in 2005, 300 ppm; and starting with 2006, 80 ppm. In the GPA,
the test result would have to exceed 350 ppm in 2004, and 300 ppm in 2005 and

2006.

We have concluded that the pipeline and terminal testing provisions are necessary for effective enforcement. We believe that terminals and pipelines will be able to perform sampling and testing that will enable them to identify the presence of small refiner gasoline in a cost-effective manner. These parties have knowledge regarding the mixing of gasoline as it moves from the pipeline and into the terminal tank, and knowledge of the distribution system,
that will enable them to make judgments regarding the extent of testing that may be needed to demonstrate whether gasoline meets the national downstream cap. Further, a terminal operator may take additional tests if it believes a tank may contain a stratified portion of small refiner gasoline, despite a test result showing the tank complies with the national downstream cap.

Many terminals may have sufficient reason to believe they are receiving only gasoline meeting the national cap such that they will not normally test each receipt of gasoline. Additionally, even
for terminals who receive small refiner gasoline, we do not believe the sampling and testing will be burdensome. This is partly because many terminals already conduct periodic sampling, or even sampling after every delivery of gasoline into storage tanks, at least in the summer VOC or RVP season, to test gasoline for various parameters, which may already include sulfur testing in
RFG areas. Field test instruments already exist that are adequate for this testing in 2004 and 2005 when the national downstream cap is 378 ppm and 326 ppm, respectively. Moreover, we believe that because of today’s rule,
better field test instruments for sulfur analysis at lower levels are likely to be developed in the next few years. Therefore, it will not be necessary for quality assurance samples to be sent to a laboratory for testing. Thus, we do not believe shipments will be held up while
terminals await a test result. We also believe that it is likely that these
instruments will be available for a cost that will be far less than most laboratory instruments available today.

Under today’s rule, retailers are not required to conduct testing. The retailer can demonstrate that the gasoline is properly designated small refiner gasoline subject to a less stringent downstream standard by maintaining PTDs from its suppliers that
demonstrate a terminal classified gasoline supplied to the retailer’s storage tank as small refiner gasoline.

Downstream Standards and Requirements for GPA Gasoline

Consistent with the way today’s rule
sets downstream sulfur standards for other gasoline, the GPA program downstream standard is determined by adding the ASTM reproducibility applicable to the refinery level sulfur


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138 As stated in section IV.C. of this preamble, the GPA states are Alaska, Idaho, Montana, North Dakota, Wyoming, Utah, Colorado and New Mexico. 139 See 40 CFR 80.46(a). Today’s rule updates the former designated test method, ASTM D 2622–94. 140 See preamble discussion in section VI.E.,

below. cap to that refinery level cap, which for GPA gasoline is as high as 350 ppm in 2004, and 300 ppm in 2005 and 2006.
This results in downstream standards for GPA gasoline of 378 ppm in 2004, and 326 ppm in 2005 and 2006.

Because GPA gasoline must be used only within the GPA states, 138 today’s rule requires that refiners and importers producing or importing gasoline subject to the GPA standards must designate each such batch of gasoline as GPA gasoline and segregate such batches from all other gasoline. Product transfer documents must identify the gasoline as GPA gasoline so that all downstream parties will be aware that it must be sold or distributed for use only in the GPA.

Gasoline produced for use in all areas of the country outside the GPA may be sold for use in the GPA, including gasoline subject to small refiner
standards under section 80.240 of today’s rule.

Where GPA gasoline is commingled with other gasoline, the commingled gasoline must be classified as GPA gasoline and used only in the GPA states. Where GPA gasoline is commingled with S–RGAS, the applicable downstream sulfur standard for that gasoline is the greater of the
GPA downstream standard or the applicable small refiner/temporary
refiner relief standard as determined
under section 80.210 of the rule.

Lead-Time for Downstream Compliance
With New Standards

Some commenters stated that there
should be a lead-time of several months between the implementation date of a new refinery level sulfur standard and the implementation date of the corresponding downstream standard. Based on our experience with otherfuels programs, we believe that a onemonth lead time will be adequate for gasoline at the terminal level to meet
new standards. An additional one month for retailers will give them ample time to comply. Therefore, under today’s rule, the 378 ppm downstream sulfur standard (or any applicable small refiner downstream cap standard) is effective February 1, 2004 at the terminal level and March 1, 2004 at the retail level. The 326 ppm downstream sulfur standard is effective February 1, 2005 at the terminal level and March 1, 2005 at the retail level. The 95 ppm
downstream standard is effective February 1, 2006 at the terminal level and March 1, 2006 at the retail level (or February 1, 2007, and March 1, 2007, respectively, in the case of gasoline at facilities in the GPA).

Retail Gasoline Pump Labeling

EPA believes gasoline advertised as being ‘‘low sulfur gasoline’’ when sold
at retail outlets should have a sulfur content of no more than 95 ppm because
this is the maximum sulfur level of gasoline at retail outlets that would protect the emission controls of Tier 2 vehicles. We are stating this to inform refiners and other regulated parties, when making advertisement decisions regarding gasoline, that it is EPA’s position that effective January 1, 2004, if any retailer represents that gasoline is low sulfur gasoline, or representations to the same effect, the gasoline sulfur content should be no greater than 95

ppm.
D. Testing and Sampling Methods and Requirements

1. Test Method for Sulfur in Gasoline

We proposed ASTM standard method D 2622–98, ‘‘Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry,’’ as the primary method for testing sulfur in gasoline by refiners and importers. This is the designated method under the
RFG/CG rule. 139 We also requested comment on adopting other methods as the primary method, in particular, ASTM method D 5453–93, ‘‘Standard
Test Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels and Oils by Ultraviolet Fluorescence,’’ and ASTM D 4045,
‘‘Standard Test Method for Sulfur in Petroleum Products by Hydrogenolysis and Rateometric Colorimetry,’’ which is used under the California fuels program for sulfur levels below 10 ppm. We also proposed ASTM D 5453 as an alternative method for determining the sulfur content of gasoline and we requested comment on this proposal.

Most comments supported the
continued use of ASTM D 2622 as the designated method for testing sulfur in gasoline under the various fuels rules, including today’s rule. Commenters
indicated that most refineries outside of California are currently using ASTM D
2622. Under the California fuels regulations, California refineries currently use ASTM D 5453, as well as
ASTM D 2622 and ASTM D 4045. Comments were generally favorable to the proposed use of ASTM D 5453 as an alternate method. However, one California refinery, an automobile
manufacturers association and a manufacturer of analytical equipment
stated that ASTM D 5453 should be the primary method, primarily due to its greater precision at low sulfur levels.
Favorable comments were received to the use of ASTM D 4045, especially for gasoline sulfur content of 10 ppm or less. One commenter suggested that ASTM D 5623–94 should be allowed; one commenter suggested that ASTM D 3120 should be allowed, and one commenter suggested that ASTM D
6428 should be allowed. Several
commenters stated that we should utilize a performance based criteria system to determine what test methods
can be used.

We have considered the comments carefully. We believe there are a number of test methods for determining the sulfur content of gasoline that may eventually be shown to be as good as, or better than, ASTM D 2622. We also considered that the Agency is likely to issue a proposed rulemaking for a performance-based test method approach that would apply to motor vehicle fuel parameters. This rule, once promulgated, would set forth criteria for determining whether an alternative analytical test method could be used instead of the designated analytical test method for a given fuel parameter and would set forth criteria for correlating alternative analytical test methods to the designated analytical test method.

We believe it is appropriate that alternate analytical methods should be qualified and correlated to the regulatory method according to standardized criteria. Today’s rule therefore provides that ASTM D 2622, the recognized standard analytical method for determining sulfur in gasoline, is the sole regulatory method, anticipating that a performance-based testing rule may be issued before 2004, and that under its terms anyone will be able to qualify and correlate additional testing methods. We do not believe this will result in undue hardship for several reasons. First, our current fuels rules already provide that ASTM D 2622 is the sole regulatory method for determining the sulfur content of gasoline. Second, California refiners currently using ASTM D 5453 or ASTM D 4045 will not face any hardship because today’s rule allows the use of approved California test methods by
California refiners. 140 Third, today’s rule allows continued use of composite samples for sulfur testing for CG during the period of early credit generation, and therefore refiners currently using outside labs to test composite samples,


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141 ASTM D 5623, entitled ‘‘Standard Test Method for Sulfur Compounds in Light Petroleum Liquids by Gas Chromatography and Sulfur
Selective Detection.’’

142 ASTM D 2784, entitled ‘‘Standard Test Method for Sulfur in liquefied Petroleum Gases’’; ASTM D 4468–85(1995), entitled ‘‘Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry’’; and ASTM D 3246–96, entitled ‘‘Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry.’’

143 ASTM D 3227, entitled ‘‘Mercaptan sulfur in Gasoline, Kerosine, Aviation Turbine, and Distillate Fuels’’. The commenter suggested it should be allowed with the use of the x-ray finish. 144 Discussed in section VI.D.3.but who may elect to conduct testing inhouse when the every-batch sulfur testing requirement is implemented,
will not need to determine whether a less expensive alternative to ASTM D 2622 is available for several years. Last, if a performance-based test method rule is not issued by the Agency in the near future, then we may reconsider this issue in a subsequent rulemaking.

We also believe that a standardized approach for determining the appropriateness of alternate test methods, correlation methodology and quality control criteria for alternate test
methods would be the most fair approach to the test equipment manufacturers and to the purchasers of testing equipment. It should result in a level playing field for competition among manufacturers of test equipment. We already know that ASTM D 5453 can be purchased for about half the price of ASTM D 2622 equipment, and competition may result in even less expensive equipment.

Some commenters suggested that where a refiner or importer uses ASTM D 2622 to test gasoline, and where the test result is less than 10 ppm, the refiner or importer should be able to report a test result of zero or perhaps use a default value of 5 ppm. This sort of approach has been allowed under the RFG and Anti-dumping Question and
Answer Document. However, we disagree with the commenters that this practice is appropriate under the sulfur rule. Under the sulfur rule, with a refiner average standard of 30 ppm, it is important whether a bias is consistently drawn in favor of zero ppm as opposed to 10 ppm. This could artificially
increase the number of credits earned or
could allow more batches to be produced by the refiner that are near the 80 ppm cap. We believe that any imprecision of sulfur values derived from analysis using ASTM D 2622, will, over the course of numerous batches, average out to near zero. Further, we believe that the precision of ASTM D 2622 is likely to be improved by 2004. Also, by 2004 there may be other
methods that will be shown to be precise at low sulfur levels that may be
made available for use under a performance-based test method rule. Under today’s rule the refiner or importer must report the test result that the test method provides, so long as the result is not less than zero (in which case a result of zero would be reported).

If alternative methods are ultimately
made available for use under a performance based rule, refiners and importers who are producing or importing gasoline with low levels of sulfur may desire to use an alternative test method for low sulfur levels, especially if ASTM D 2622 is less precise at such levels. Under today’s rule, if any approved alternative method is used for this purpose, a party could
not choose to use the test result from ASTM D 2622 when its result is lower,
and the test result from the alternative method when its result is lower. For any
alternative test method that is eventually approved, if the party uses it for a certain range of sulfur concentrations, and ASTM D 2622 for another range, it must be consistent in such use. For example, if the alternate
method were used for test results below 10 ppm, its result would always have to be used for sulfur levels below 10 ppm and ASTM D 2622 would always have to be used for sulfur levels greater than 10 ppm.

2. Test Method for Sulfur in Butane

We proposed the use of ASTM
standard test method D 5623–94 141 as the designated method for testing the sulfur content of butane and requested
comment on whether this method should be the designated method. Although some butane suppliers or refiners currently use this method, several commenters stated that many refiners do not have ready access to
ASTM D 5623 and that it is not necessarily the most precise method for
determination of low levels of sulfur in butane. Commenters suggested at least three other methods are equal to ASTM D 5623. These are ASTM D 2784, ASTM D 4468, and ASTM D 3246. 142 One commenter also suggested that ASTM D

3227–92, 143 should be allowed. Several commenters requested that EPA at least
allow alternative test methods for quality assurance testing.

We have reviewed the suitability of ASTM D 5623 and agree that it is not the best method for testing for sulfur
content in butane. ASTM D 5623 measures sulfur compounds rather than total elemental sulfur, and the current ASTM 5623 method is specified for liquid fuels, not gaseous fuels.

ASTM D 2784 does not seem to be a
better method than ASTM D 5623. Commenters stated that ASTM D 2784 is not the most precise method and that it is not widely used. We believe there may be some difficulty in even obtaining the apparatus for ASTM D 2784. ASTM D 3227 is not appropriate since it is designed for measuring a single sulfur compound, and it is currently designated for testing liquid samples.

We believe that ASTM D 4468 appears to be a good method for testing butane for sulfur levels below 20 ppm. However, dilution would be necessary to test for sulfur levels above 20 ppm. This may be problematical, since it may be difficult to dilute a gaseous fuel. We expect that under today’s rule, butane being tested will frequently have sulfur content in excess of 20 ppm. Several other methods exist that might work well for testing for sulfur content of gaseous fuels, but their current scope
does not include determination of sulfur in gaseous fuels.

ASTM D 3246–96, which was suggested by API and NPRA as a suitable method, is an appropriate method for measuring gaseous compounds and provides test results for total elemental sulfur. Its range is 1.5 to 100 ppm, which is ideal for testing for the alternative 30 ppm butane sulfur standard applicable to butane blenders promulgated in today’s rule. 144

After considering the strengths and weaknesses of all the available options
we believe ASTM D 3246 is the best currently-available method. Therefore, today’s rule makes ASTM D 3246 the designated method for testing the sulfur content of butane or other gaseous blendstocks. As discussed above, we anticipate that a performance-based test
method rule for motor vehicle fuel parameters may be promulgated before 2004, and that the efficacy of other
methods would be demonstrable under that rule. However, if that is not the case, the Agency may reconsider the issue of appropriate alternate test methods in a future rulemaking.

3. Quality Assurance Testing

Several commenters urged that
alternate test methods be allowed for quality assurance test purposes. Under today’s rule, the use of alternate test methods for quality assurance testing for purposes of establishing a defense to liability, for butane quality assurance testing under section 80.340(b)(4), and for determination of whether gasoline is small refiner gasoline, is allowed, so long as the alternate test method is correlated to the regulatory test method, the method is ASTM approved, and the


### 6807 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

145 Except for certain truck importers, as noted

above.

146 As noted above, we are not requiring every batch testing for CG parameters other than sulfur. protocols under the method are followed. However, the regulatory method is required for the truck importer quality assurance testing under section 80.350(c).

4. Requirement To Test Every Batch of Gasoline Produced or Imported

We proposed in the NPRM that refiners and importers 145 would be required to sample each batch of gasoline produced or imported and perform a test on each sample to determine the sulfur content prior to the gasoline leaving the refinery gate or importer facility. We received comments on several aspects of this proposed requirement.

Several commenters urged that we continue to allow composite sampling and testing for sulfur. Some refiners commented that the requirement to test each batch would raise testing costs. However, one refiner commented that every-batch testing for sulfur would notbe a substantial burden so long as everybatch testing for other CG parameters is not required. 146 This commenter stated that testing for sulfur content is much less complex than testing for certain other CG parameters.

We believe that with a refinery gate sulfur cap combined with refinery averaged standards, there is no realistic alternative to every-batch testing. The Agency has no way to know whether a composite sample that is tested and found to meet the applicable refinery cap included a sample from an individual batch of gasoline that was
introduced into commerce that exceeded the cap by a factor of 2 or 3. Further, we believe that with averaged standards for refiners and importers, and with multiple cap standards in effect during the phase-in period,monitoring compliance without everybatch testing would be impossible even
if we could somehow be assured that no individual batch significantly exceeded the applicable refinery level cap.

We realize that there will be an additional cost associated with testing every batch of CG—for sulfur content (this is already required for RFG). However, we believe less expensive test methods for sulfur content already exist, and may continue to be developed, that will likely be acceptable as alternative methods in the future, as discussed above. Therefore, today’s rule retains the requirement for every-batch testing. Under today’s final rule, the test results for each batch of gasoline will be used to determine compliance with the applicable refiner/importer cap standard
and to calculate the refiner’s or importer’s annual average sulfur level. Any batch of gasoline that exceeds the applicable sulfur cap cannot be distributed or sold in the U.S. (unless it is exempted from the standards under today’s rule, as described in section VI.G., below).

Refiners who use computerized inline blending methods objected to the proposed requirement for a batch test before the gasoline is released from the refinery. These commenters stated that refiners using the sophisticated in-line blending practice cannot produce a complete batch test until a portion of the batch is already past the refinery gate. These commenters did not urge that we eliminate the requirement for every-batch testing, but urged that the sulfur rule adopt the RFG rule provisions for in-line blending found at 40 CFR 80.65(f)(4), for both RFG and

CG.

We believe that the importance of assuring compliance with the refinery level cap is such that the rule must generally require that gasoline must be
tested for sulfur content before it leaves the refinery. Based on experience under the RFG rule, we do not believe that the requirement to test each batch before it is released will substantially increase the cost of testing or cause delays in shipments.

However, today’s rule recognizes the unique circumstances involved in computerized in-line blending. We believe that with appropriate safeguards, compliance with sulfur standards for gasoline produced by refineries using in-line blending can be assured. Therefore, today’s rule incorporates the RFG rule provisions for in-line blending at 40 CFR 80.65(f)(4). Such provisions will be applicable to RFG and CG. However, refineries presently having an in-line blending
waiver will be asked to submit
additional information under the auditing procedures included in approvals of in-line blending petitions already in place. We will contact individual holders of in-line blending approvals to request information on
how sulfur is monitored and how streams of gasoline are distributed in the in-line blending process. If we cannot conclude that the monitoring procedures will assure compliance withsulfur standards, we will revoke the inline blending approval for that purpose. We believe it is important to ensure that the in-line analyzer technology and the refiner’s methodology and procedures are sufficient for the gasoline sulfur levels the refinery will have after this rule is implemented, for both RFG and

CG.

Several commenters stated that the proposed rule’s requirement to test every batch of CG for sulfur is unnecessary during the period of early credit generation because there is no cap standard in effect during this period, even for those refiners generating credits. We agree that every-batch testing is not essential for CG until the refinery gate per-gallon cap standards go into effect. Thus, today’s final rule allows composite sample testing for CG to continue during the period of early credits generation, until January 1, 2004, when a cap standard for sulfur is first imposed on gasoline.

5. Exceptions to the Every-Batch Testing Requirement

Under the RFG rule, refiners who
blend butane or other blendstocks to previously certified gasoline (PCG) must determine the volume and parameter values of the blendstock, including sulfur content, by testing the gasoline before and after blending, and calculating the properties of the blendstock by subtracting the volume and parameter values of the PCG. For CG only, under certain conditions, we
have allowed butane blenders to use the parameter specifications of butane as tested by the butane producer. We have allowed this alternative to every-batch testing because of the costs of testing each load of butane. We proposed a similar alternative to every-batch testing for butane blenders in the NPRM, which
allows butane blenders to use the sulfur test result of their suppliers, if the butane contains no more than 30 ppm
sulfur and if the butane blender undertakes a quality assurance program of periodic sampling and testing to ensure that the supplier’s sampling and testing is accurate.

We also proposed to allow refiners
that blend other blendstocks into PCG to meet an alternative testing requirement in lieu of testing every batch of gasoline.
Provided that the refiner’s test result for
the sulfur content of each of the
blendstocks is less than the national refinery level per-gallon cap standard, a refiner can sample and test each
blendstock when received at the refinery, and treat each blendstock receipt as a separate batch for purposes of compliance calculations for the annual average sulfur standard.

Today’s rule adopts these provisions. Several commenters urged us to delay the 30 ppm per-gallon cap standard until other refiners must meet a 30 ppm average standard. The proposed 30 ppm per gallon standard was intended to be environmentally neutral in relation to


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147 See Table IV.C.–1.

148 See the discussion on this subject in the preamble to the reformulated gasoline program’s final rule, 59 FR 7765 (Feb. 16, 1994). 149 See 40 CFR 80.65(f)(3)(F)(ii), and the Proposed

Rule for Modifications to Standards and Requirements for Reformulated and Conventional Gasoline, 62 FR 37337 et seq, proposed 40 CFR 80.101(i)(1)(i)(C)(iii). the standard applicable to other refiners. Therefore, today’s final rule makes clear that for the alternative compliance approach for butane blenders, the 30 ppm per-gallon cap is not applicable until January 1, 2005. The per-gallon cap starting January 1, 2004 is 120

ppm. 147 For GPA gasoline the per-gallon cap under this alternative compliance option is 150 ppm in 2004 through

2006.

6. Sampling Methods

Sampling methods apply to all parties who conduct sampling and testing under the rule. We proposed to require the use of sampling methods that were proposed in the July 11, 1997 Federal Register notice for the RFG/CG rule (62
FR 37338, at 37341–37342, 37375– 37376). These sampling methods include ASTM D 4057–95 (manual sampling), ASTM D 4177–95 (automatic sampling from pipelines/in-line blending), and ASTM D 5842 (this sampling method is primarily concerned with sampling where gasoline volatility is going to be tested, but it would also be an appropriate sampling method to use when testing for sulfur). There were no adverse comments to the proposed sampling provisions. Today’s rule adopts the methods as proposed.

7. Gasoline Sample Retention Requirements

In the NPRM, we proposed a refiner and importer (collectively referred to in this section as ‘‘refiner’’) sampling and testing program to establish the sulfur compliance of each batch of gasoline produced or imported. We were aware that there were possible drawbacks to a self-testing scheme. For example, a party might sample or test gasoline in a
manner that is inconsistent with the required procedures, or employees might inaccurately record the test results by mistake or otherwise. Parties might also attempt to conceal a discovered violation or to save money by not correcting a violation.

To address our concerns about selftesting, we considered an alternative option of requiring independent sampling and testing for all gasoline, including conventional gasoline. We did not propose this requirement for independent sampling and testing for all gasoline because of the costs of such a requirement, 148 and we are not adopting such a program in today’s final rule. Instead, we proposed in the NPRM a different strategy to complement the self-testing program that would help ensure refinery sulfur compliance. This strategy would have required refiners to retain for thirty days a representative sample from each batch of gasoline produced, and to provide such samples to the Agency upon request. We believed that, by means of this option, EPA could verify the refiner test results.
We believe that this would create an incentive for refiners to sample, test,
and record their sulfur results in an
accurate and truthful manner. We also proposed that refiners be required to certify annually that the samples have been collected in the manner required under the sulfur rule. In addition, we proposed that specific procedures be followed by refiners to properly collect, retain, and ship the samples in a manner consistent with requirements already imposed or proposed under the RFG program. Under the proposal, a minimum representative sample of 330 ml of each gasoline batch would need to be retained (and submitted to EPA upon request). 149

Although there were few comments on this proposal, one commenter, the
National Petrochemical & Refiners Association (‘‘NPRA’’), did comment extensively on it, and strongly urged the Agency not to finalize it. One of the points raised by the NPRA was that the RFG regulations have their own sample retention and submission requirements, (40 CFR 80.65), so that a sulfur rule provision for RFG batches was not necessary. The Agency continues to believe that sample and retention requirements are useful to ensure compliance with the sulfur standards, but we agree with NPRA that the sample retention and submission requirements found in the RFG rule will serve equally as well for the sulfur rule. Therefore, the final sulfur rule requires all refiners, including those producing RFG, to comply with the sulfur rule’s retention requirements. However, any refiner of RFG using an independent laboratory pursuant to 40 CFR 80.65(f), either under the 100% Option or the 10% Option, will be considered to be in compliance with the sulfur rule’s retain requirements provided the refiner ensures that the independent laboratory conducting the retain program for the refiner, is in compliance with these requirements. In particular, the refiner must ensure that its independent laboratory sends the appropriate certificate of analysis along with any sample forwarded to EPA. Under the RFG program’s 100% Option, the refiner must ensure that its independent laboratory sends the independent lab’s certificate of analysis; and under the 10% Option, the refiner must ensure that its independent laboratory sends the refiner’s certificate of analysis.

In addition to urging EPA not to finalize the sample retention and submission requirements for RFG gasoline, NPRA urged us not to finalize these requirements for CG as well. NPRA argued that these requirements would not prove useful in deterring non-compliance with the sulfur requirements for this product, primarily because false samples could be forwarded to EPA. The Agency disagrees with NPRA’s argument. First, the goal of these requirements is not only to deter cheating but also to reveal inadequacies that exist in refiners’ sulfur testing procedures. We do not expect that most non-compliance with the sulfur standards will occur through cheating, but rather through operational problems. Agency enforcement experience under the RFG rule reveals that some refiners’ testing procedures are not always accurate in measuring parameters and thus detecting noncompliance. EPA verification testing will expose such testing inaccuracy, enabling the refiner to improve its testing procedures and thus improve its ability to detect, and correct, its own compliance problems. To ensure the effectiveness of these sulfur sample retention and submission requirements, the final rule requires all refiners to provide EPA with the sulfur test result the refiner has obtained for the sample, along with each sample the refiner provides to the Agency under this rule.

EPA will use these retained samples in compliance determinations. Gasoline samples that are forwarded to EPA under the sample retention requirements that are found to be in violation of a refinery cap, will be considered by EPA to be evidence of violations of the cap standard, regardless of the refiner’s own test result. In addition, EPA testing of these samples may establish that the refiners’ test results are generally incorrect, i.e.

, are biased. EPA will evaluate whether
such a bias constitutes evidence of a violation of the sulfur average standards applicable to the refiner, including
whether the bias extends to other sulfur tests conducted by the refiner during the current or previous averaging periods. Further, evidence of testing bias could
constitute evidence a refiner has not met the requirement to conduct sulfur testing in accordance with specified


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150 See 40 CFR 80.81(g). procedures, and any reports submitted
to EPA that reflect the bias could be
evidence a refiner has not met the requirement to properly report the sulfur content of gasoline produced.

While it is true that a party can submit false samples to EPA in order to prevent the Agency from discovering what in actuality is a non-compliant batch of gasoline, we do not believe that there will be many examples of such flagrant cheating. Our enforcement experience indicates that the great majority of parties regulated under the fuels programs work to comply with the regulatory requirements. We believe that the potential penalties for the submission of false samples to the government, and the potential criminal liability which such conduct would subject parties to under to section 113 of the Clean Air Act, will act as significant deterrents to this cheating. Last, to further decrease perceived incentives for such cheating, the regulation specifically requires that the refinery official signing and submitting the refinery’s annual sulfur report must make inquiries to verify the correctness of the sampling collection and retention procedures and include with the annual sulfur report a personal certification of the correctness of the procedures used to collect the retained samples. If such certification cannot be made, then the report cannot be timely filed.

NPRA further commented that CG being counted to create early credits under the sulfur rule’s ABT program should not be subject to the proposed sample retention and submission requirements. NPRA argues that the lack of a sulfur cap during the early credit
timeframe makes such retention and submission unnecessary. The Agency disagrees. During the early credit generation timeframe, refiners participating in the credit program must comply with sulfur averaging requirements, even though sulfur caps are not required to be met. Accurate determination of compliance with the averaging requirements necessitates accurate sulfur testing in the early credit period, just as it does during implementation of the full sulfur program, even though sulfur testing of CG composite samples will be permitted. Hence, the sample retention and submission requirements, whose purpose is to ensure accurate testing and compliance determination, continue to be necessary for the early credit period. The final rule retains the sample retention requirements for CG during the early credit time frame.

NPRA also suggested that in place of the proposed 30 day sample retention requirement, EPA instead should require refiners to maintain samples only from the last three batches of gasoline produced. NPRA argued that this alternative requirement would prove more economical for the refiners, yet would still provide EPA with the ability to test some samples itself. Although the Agency believes that the proposed 30 day retention period would provide a valuable amount of samples to be retained and thus available for testing by EPA, the Agency agrees that a more limited sample retention requirement could provide an acceptable means of confirming refiner testing accuracy and sulfur compliance, while being less
burdensome to refiners. We do not believe, however, that retention of samples from only three batches of gasoline would be effective in accomplishing the goal of producing greater testing accuracy. Three samples would not be a great enough number to realistically demonstrate if a pattern of testing irregularities exists or to demonstrate that a significant volume of the refiner’s production is covered by the testing verification process. Consequently, instead of the three batch sample retention requirement proposed by this commenter, the Agency has instead required in the final rule that at least the last 20 samples be retained, and that each sample be retained for a minimum of 21 days. The Agency believes this amended requirement
addresses NPRA’s concern that the amount of days of sample retention be reduced from thirty days, while also providing the Agency with an effective means of assuring a reasonable number of samples, representing a significant period of refining activity, will be available for accuracy testing. We believe the retention requirement is not burdensome given the limited number of samples that must be retained. Further, many refineries already retain samples.

A final comment by NPRA about the sample retention and submission requirements is addressed in the final
rule. NPRA raised a concern about the required retention and submission of samples of pressurized blendstock, particularly butane, which wouldrequire the use of specialized highpressure containers. The Agency agrees that there is legitimate concern about the handling, storing and shipping of such samples. We also believe that the final rule’s quality assurance testing requirements and the testing requirements for blendstock suppliers provides adequate assurance of the compliance of these blendstocks. Hence,
the final sulfur rule does not contain a requirement that samples of pressurized
blendstock must be retained.

E. Federal Enforcement Provisions for California Gasoline and for Use of California Test Methods To Determine Compliance

Requirements to Segregate Gasoline and
to Use Product Transfer Documents for Certain California gasoline; Definition of
California Gasoline

In the NPRM, the Agency proposed to generally exempt from the requirements of the federal sulfur rule certain gasoline
sold or intended for sale in California. For the purpose of program consistency, the gasoline to be exempt in the sulfur
rule would meet the same definition of California gasoline as found in the RFG rule (40 CFR 80.81(a)(2)). The exempt gasoline would include all gasoline sold, intended for sale, or made
available for sale in California that was also either: produced within California; imported into California from outside the U.S.; or imported into California from another state, provided that the out-of-state refinery did not also produce federal RFG.

Although the NPRM proposed to exempt California gasoline from compliance with the proposed sulfur standards (for reasons discussed elsewhere in this preamble), we did propose two requirements that would apply to some exempt California gasoline. The first would require exempt gasoline produced outside of California but intended for use in California, to be segregated from non-exempt gasoline at all points in the distribution system. The second would require out-of-state producers of exempt gasoline intended
for sale in California to create PTDs identifying the product as California gasoline, and would require such PTDs to be provided to all transferees of this gasoline in the distribution system. Requiring such documentation is
intended to facilitate enforcement and compliance by identifying gasoline that is not federally regulated. The same PTD requirements currently apply under the RFG program. 150

One commenter expressed a
reservation about the sulfur rule’s proposed segregation requirement. The
commenter was concerned that the segregation requirement for exempt California gasoline might interfere with the ability of California importers to import into California, non-exempt, federal RFG gasoline that happened to comply with California Air Resources Board (ARB) sulfur requirements, buthad not been kept segregated by its outVerDate 27<JAN>2000 21:29 Feb 09, 2000 Jkt 190000 PO 00000 Frm 00113 Fmt 4701 Sfmt 4700 E:\FR\FM\10FER2.SGM pfrm08 PsN: 10FER2

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of-state refiner from the refiner’s federal RFG product. Out of a concern about potential gasoline supply problems in California, the commenter asked for assurances from the Agency that such gasoline would not be prohibited from
sale in California because of the sulfur rule’s segregation requirement.

The Agency agrees that it would not
be beneficial to restrict the flow of complying gasoline into California. However, since the federal and the ARB sulfur control programs provide for differing calculations of standard compliance, and since the standards themselves are not always consistent between the two programs, EPA does not believe that the compliance of gasoline produced for federal purposes will necessarily assure its compliance with ARB program requirements, and vice-versa. Therefore, we believe it is necessary to require the physical segregation of the gasolines produced for the different programs in order to best ensure compliance with our uniquely determined federal sulfur standards. To ensure segregation, it is necessary that refiners and importers designate gasoline batches destined for California as California gasoline and that PTDs identify the gasoline as being for use only in California.

Further, one of the purposes of creating the California exemption in the
federal sulfur rule is to ensure the exclusion of California gasoline from the refiner’s compliance calculations under
the federal rule. This exclusion is necessary to prevent gasoline that is produced to comply with the strict California standards from unfairly effecting the refiner’s compliance with the federal requirements, thereby facilitating the production of higher sulfur gasoline for use in a federal market supplied by the refiner. EPA believes that segregation of the two gasolines is necessary because it
facilitates accurate identification of the product to be included solely in the federal compliance calculations.

EPA does not believe that requiring the segregation of California gasoline from gasoline produced for the federal market should create a significant restriction in the flow of gasoline to California. The Agency believes that if a California marketer needs to acquireARB-complying gasoline from out-ofstate, the marketer should generally be able to satisfy that need by ordering a batch of California gasoline to be created for it by out-of-state producers. Under
this circumstance of the creation of a unique batch of California gasoline, segregation of the gasoline will typically
be assured. In analyzing the above comment on segregation of California gasoline, the Agency realized that the sulfur rule’s proposed definition of exempted California gasoline, which paralleled the definition existing in the RFG rule, was not as complete as it should be to properly address the unique needs of the sulfur program. Specifically, the
exclusion from the sulfur rule’s exemption of out-of-state gasoline sold or intended for sale in California solely because it happens to be produced at a refinery that produces federal RFG gasoline, is not appropriate. Basing anexemption on whether or not an out-ofstate refinery produces federal RFG is relevant to the RFG program, but it has
no relevance to the sulfur control program. To ensure effective determination of compliance with federal sulfur standards, the final sulfur rule deletes any reference to RFG production in the rule’s definition of exempt California gasoline. Hence, the example presented in the comment, in which out-of-state gasoline for sale in
California could be considered nonexempt gasoline, would not arise under the expanded definition of California gasoline.

Use of California Test Methods and OffSite Sampling Procedures for 49 State
Gasoline

Under the NPRM and the final rule, refineries and importers located in California would be required to meet the
federal sulfur standards and other requirements with regard to their ‘‘federal’’ gasoline to be used outside of California. However, we proposed that gasoline produced in California for sale
outside of California could be tested for compliance under the federal sulfur rule using the methodologies approved by the ARB, provided that the producer complies with the procedures for such testing as already required under 40 CFR 80.81(h), which permits California
test methods not identical to federal test
methods to be used for conventional gasoline. Today’s rule adopts this provision, as well as the corollary proposed provision that gasoline produced by California refiners for use out-of-state may be tested at off-site testing as already permitted pursuant to 40 CFR 80.81(h) for CG purposes. Both provisions in today’s rule should alleviate duplicate testing burdens on California refiners subject to both the federal and California programs, since the test methods acceptable under these alternative provisions in today’s rule are also currently used to comply with California requirements. No comments were received on these provisions. F. Recordkeeping and Reporting Requirements

1. Product Transfer Documents

Small Refiner Gasoline Transfers

The NPRM proposed that the business practice PTDs that accompany each transfer of custody or title of gasoline that includes gasoline produced by any small refiner subject to sulfur rule individual refinery standards would be required to identify the gasoline as such, including the applicable downstream cap, as an aid to enforcing the national downstream cap. Today’s rule adopts the proposed PTD requirement, with modifications regarding how the PTD requirement relates to testing, as
described in section VI.C. The requirement for printing information on PTDs has been simplified in the final rule. All parties may use brief codes to identify the small refiner status of the gasoline and to identify the small refiner downstream standard it is subject to. This small refiner gasoline PTD provision is also applied to gasoline subject to individual refinery standards under the temporary refiner relief provision of today’s rule.

GPA Gasoline Transfers

Under the geographic phase-in program finalized today, gasoline produced or imported for use in the GPA may be used only in the GPA states. Therefore, it is necessary for PTDs for gasoline that is comprised in whole, or in part, of GPA gasoline, to identify the gasoline as such and state that the gasoline may not be distributed
or sold for use outside the GPA. Product codes may be used to provide this information, except in the case of transfers to truck carriers, retailers and wholesale purchaser-consumers.

2. Recordkeeping Requirements

Under today’s rule, refiners and importers will be required to keep and
make available to EPA certain records that demonstrate compliance with the sulfur program standards and requirements. This includes records pertaining to the generation, use and
transfer of credits and allotments. The RFG/CG regulations currently require refiners and importers to retain records
that include much of the information required in the sulfur rule. Where this is the case, there is no requirement for duplication of records or information.

Under the final rule, all parties in the gasoline distribution system, including refiners, importers, oxygenate blenders, retailers, and all types of distributors will be required to retain PTDs and records of quality assurance programs (including, where applicable, sulfur test


### 6811 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

151 Five years is the applicable statute of limitations for the RFG and other fuels programs.

See 28 U.S.C. 2462. results) that parties conduct to establish
a defense to downstream violations. All parties in the gasoline distribution system currently are required to keep PTDs for RFG. However, since there are
no downstream CG standards under the anti-dumping regulations, only refiners and importers are required to retain PTDs for conventional gasoline under the current regulations. Because the sulfur rule, like the RFG rule, includes downstream standards, we believe that a requirement to retain PTDs for all parties in the gasoline distribution system is appropriate under the sulfur rule. The PTD information will help us identify the source of any gasoline
found to be in violation of the sulfur standards, and will provide downstream parties with information regarding the applicable downstream standard.

Parties are required to keep records for a period of five years, 151 with additional requirements for records pertaining to credits and allotments. Records pertaining to credits or
allotments that were banked and never transferred to another party are required to be retained for five years after the
credits or allotments are used for compliance purposes. Records pertaining to credits or allotments that were transferred are required to be retained by the transferor for five years after the year the credits or allotments were transferred, and by the transferee for five years after use.

We received comment that the regulations should allow records to be maintained in non-hard copy formats, such as photographic or electronic
means. We do not believe that the recordkeeping requirements, as proposed, disallow the retention of records in electronic or photographic form. However, parties that electronically generate and/or maintain
records must make available to EPA the hardware and software necessary to review the records, or if requested by EPA, electronic records shall be converted to paper documents.

The sulfur rule, like the RFG/CG rule, requires regulated parties to keep the
results of tests conducted on the gasoline. A number of parties previously have asked EPA to clarify whether, under the RFG/CG rule, this recordkeeping requirement requires parties to keep copies of all documents that contain test results. To clarify what the recordkeeping requirements require with regard to test data, we proposed for the RFG/CG rule to add language which specifies that the test result as originally printed by the testing apparatus is required to be kept, or, where no printed result is generated by the testing apparatus, the results as originally recorded by the person who performed the tests. Today’s action incorporates
this clarification in the sulfur rule. Under this provision, where the test data is initially recorded into a database system and there are no prior written recordings of the data, the information in the database system may serve as the original record of the test data. The final rule also specifies that any record that
contains results for a test that are not identical to the results as originally printed by the testing apparatus or recorded by the person who performed the test must also be kept. Although this language was not included in the NPRM, we have concluded it is a logical outgrowth of the proposal regarding recordkeeping for test data, and that it will make the regulation clearer with regard to this requirement. As a result, it is appropriate to include this language
in the final rule.

3. Reporting Requirements

Refiners and importers will be required to submit an annual report that demonstrates compliance with the applicable sulfur standards and data on individual batches of gasoline, including batch volume and sulfur content. The rule requires that refiners and importers report on the generation,
use and transfer of credits and allotments. The RFG/CG programs contain similar reporting requirements. Based on our experience with these programs, we believe that requiring an annual sulfur report and batch information will provide an appropriate and effective means of monitoring compliance with the average standards under the sulfur program. The batch data also will serve to verify that each batch of gasoline met the applicable sulfur cap standard when it left the refinery or import facility. The batch
data must also show which batches were designated as GPA gasoline, as appropriate.

For the 2004 and 2005 annual averaging periods, refiners will be required to submit a report for the refiner’s gasoline production (RFG and conventional gasoline) for all refineries during the averaging period, which demonstrates compliance with theapplicable corporate average and pergallon cap standards. For the 2005 annual averaging period, refiners will also be required to submit a separate report for each refinery, which demonstrates compliance with the refinery average standard. For the 2004 and 2005 annual averaging periods, importers will be required to submit a report for all of the gasoline they import during the averaging period, which demonstrates compliance with theapplicable corporate average and pergallon cap standards. The importer’s report for 2005 must also demonstrate compliance with the refinery average (30 ppm) standard. Any refiner who is also an importer must aggregate the refining and importing activities for the purpose of demonstrating compliance with the applicable corporate average standards. Importers of gasoline produced by foreign refiners with
individual baselines have additional reporting requirements. For the 2006 averaging period and beyond, corporate average reports are no longer required for either refiners or importers. Refiners will be required to submit an annual report for each refinery (importers for the gasoline they import), which demonstrates compliance with the refinery average and per-gallon cap standards. Refiners or importers producing both GPA gasoline and gasoline for the remainder of the country, must separately report compliance with the different standards. Annual reports, on forms provided by the Agency, must be received by EPA by the last day of February for the prior calendar year.

The annual reports will also provide a vehicle for accounting for any sulfur allotments or credits created, sold or used to achieve compliance during the averaging period. (See Section IV.C. for
a discussion of the sulfur allotment and ABT credit programs.) Each refiner or importer choosing to participate in the ABT program will be required to report to the Agency on an annual basis (refiners for each refinery, and importers for the gasoline they import) the applicable sulfur baseline and the annual average gasoline sulfur level produced at that refinery or by that importer (in ppm sulfur) during the averaging period. Credit calculations will be reported, along with an accounting of credits banked, used, traded, acquired or terminated. The credits will be in units of ppm-gallons. The identity of the refiners/refineries and importers involved in these transactions will be reported, along with the registration numbers assigned to them by the Agency under the RFG/CG program (40 CFR 80, subparts D, E, and F).

For years 2000 through 2003, parties who generate early ABT credits will be required to report information relating to the generation of these credits. These early credit reports will only cover credits banked and traded. Beginning in 2004 and beyond, refiners and importers


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152 See section 80.5 (penalties for fuels violations); section 80.23 (liability for lead violations); section 80.28 (liability for volatility violations); section 80.30 (liability for diesel violations); section 80.79 (liability for violation of RFG prohibited acts); section 80.80 (penalties for RFG/CG violations).

153 An additional type of liability, vicarious liability, is also imposed on branded refiners under these fuels programs. who generate and/or use ABT credits will be required to submit information relating to the generation and use of the credits as part of their annual compliance reports, including any
credit debit that is carried over to the subsequent year. For each purchase of ABT credits, as reported on the buyer’s annual report, there must be a corresponding entry on the seller’s annual report. The annual report must also indicate any credits that are used to achieve compliance with the refinery average standard.

As discussed above, during the 2004 and 2005 annual averaging periods, refiners for the combined production from all their refineries, and importers for the gasoline they import, will also be required to demonstrate compliance with the applicable corporate average standard. In addition, refiners and importers must demonstrate compliance with the requirements for the generation, use, transfer and termination of allotments. Refiners and importers
who trade sulfur allotments to meet the corporate average standard will be required to submit information relating
to these transactions. All sulfur
allotment transactions must be concluded by the last day of February of the calendar year following the year the
allotments were used to meet the corporate average. Information relating to such transactions, including the identity of the refiners and importers
involved in the transactions and their EPA registration numbers, must be reported by both parties to the transaction as part of their annual compliance reports.

As discussed in Section IV.C., above, parties that only blend oxygenates into gasoline are not treated as refiners under the sulfur rule, and, as a result, are not subject to the reporting requirements under § 80.370.

Refiners and importers are also required to arrange for a certified public
accountant or certified internal auditor
to conduct an annual review of the company’s records that form the basis of the annual sulfur compliance report (called an ‘‘attest engagement’’). The purpose of the attest engagement is to determine whether representations by the company are supported by the company’s internal records. Attest engagements are already required under the RFG/CG regulations. The refiner’s attest engagement under the RFG/CG rule partially encompasses sulfur rule compliance since the attest auditors are already required to verify sulfur results for both CG and RFG. However, the RFG/CG attest engagements do not require the attest auditor to review sulfur credit generation, credit purchases, credit trading or small
refiner issues. Because of the complexity of the sulfur credit program and small refiner program, sulfur attest engagement provisions have been adopted by today’s rule that require the
attest auditor to review sulfur credit generation, credit trading, credit purchasing, credit selling, corporate pool averaging, and small refiner issues. Consistent with the RFG regulations, the attest reports for sulfur are to be included in the presently required attest engagement submitted by May 31 of each year.

G. Exemptions for Research, Development, and Testing

The final rule provides for an exemption from the sulfur requirements for gasoline used for research, development and testing purposes. We recognize that there may be legitimate research programs that require the use of gasoline with higher sulfur levels
than those allowed under the sulfur rule. As a result, the final rule includes provisions for obtaining an exemption from the prohibitions for persons distributing, transporting, storing, selling or dispensing gasoline that exceeds the standards, where such gasoline is necessary to conduct a research, development or testing program. Parties are required to submit to EPA an application for exemption that describes the purpose and scope of the program and the reasons why use of the higher sulfur gasoline is necessary. In approving any application, EPA will impose reasonable conditions such as recordkeeping, reporting, volume limitations and possible requirements to repair vehicles.

We received comment that the regulations should clarify that suppliers of gasoline used for R&D purposes are exempt from the prohibitions and penalties under the sulfur rule. To clarify this point, we have added a provision which explicitly states that gasoline subject to an R&D exemption is exempt from the provisions of subpart H, so long as the gasoline is used in a way that complies with the terms of the memorandum of exemption. If the R&D exemption is shown to be based on false information or is not properly maintained, parties will be liable for violations of the provisions under subpart H regarding any gasoline covered under the exemption.

We also received comment that the regulations should ensure that vehicles which have been used for testing with high sulfur test fuels are not later returned to the general fleet, or if they are, the vehicles should be required to be restored to their original condition. EPA agrees that it would be improper to permit such vehicles to be used in general use if their emission controls have been rendered inoperative through fueling with high sulfur gasoline. This issue may be effectively addressed through the anti-tampering requirements of section 203(a)(3) of the Clean Air Act, 42 U.S.C. § 7522(a)(3), and is also addressed in today’s rule, which provides the Administrator with the power to include appropriate conditions when granting R&D exemptions.

H. Liability and Penalty Provisions for Noncompliance

The liability and penalty provisions
under the sulfur rule are similar to the liability and penalty provisions of the RFG and other fuels regulations. 152 Regulated parties will be liable for committing certain prohibited acts, such as selling or distributing gasoline that does not meet the sulfur standards, or causing others to commit prohibited acts. In addition, parties will be liable
for a failure to meet certain affirmative requirements, such as the recordkeeping or PTD requirements, or causing others to fail to meet such requirements.

The sulfur rule, like other EPA fuels regulations, includes a presumptive liability scheme for violations of prohibited acts. Under this approach, the party in the gasoline distribution system that controls the facility where the violation occurred, and other parties in that gasoline’s distribution system (such as the refiner, reseller, and distributor), are presumed liable for the
violation. 153 The sulfur rule explicitly includes causing another person to commit a prohibited act and causing the presence of non-conforming gasoline to be in the distribution system as prohibitions. The final rule clarifies that causing the presence of non-conforming gasoline to be in the distribution system includes gasoline that does not conform to the applicable average standard, as well as gasoline that does not conform to the cap standard. Affirmative defenses are provided for each party that is deemed presumptively liable for a violation, and all presumptions of liability are refutable. The defenses
under the sulfur rule are similar to those


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available to parties for violations of the RFG regulations.

The final sulfur rule, like the proposal, applies the provisions of section 211(d)(1) of the Clean Air Act (Act) for the collection of penalties. The penalty provisions subject any person who violates any requirement or prohibition of the sulfur rule to a civil penalty of up to $27,500 for every day
of each such violation and the amount of economic benefit or savings resulting
from the violation. A violation of the applicable average sulfur standard constitutes a separate day of violation for each day in the averaging period. A violation of a sulfur cap standard constitutes a separate day of violation for each day the gasoline giving rise to the violation remained in the gasoline distribution system. The length of time the gasoline in question remained in the distribution system is deemed to be twenty-five days unless there is evidence that the gasoline remained in the gasoline distribution system for fewer than or more than twenty-five days. The penalty provisions are similar to the penalty provisions for violations of the RFG regulations.

After consideration of the comments received, the Agency is adopting regulations that specify the regulated parties who may be subject to liability for causing a violation of the sulfur rule. As proposed, the regulation would have applied to any person, not limited to the parties in the gasoline distribution system whose actions could logically have caused the nonconformity. This provision would have potentially broadened the range of liable parties under the sulfur rule beyond the range established under other fuel programs. EPA believes that the presumptive liability schemes of current fuels regulations have generally been effective and finds no compelling reason to apply the regulatory provision at issue to ‘‘any person’’ rather than to specific parties. Therefore, in the final sulfur rule, the liability sections for the causation violations will specify the regulated parties subject to the liability, and will not encompass unspecified parties. The final rule clarifies that oxygenate blenders are among the specified parties potentially subject to liability. Today’s final rule also clarifies that parent corporations are liable for violations of
subsidiaries. This is consistent with our interpretation of the RFG rule, as stated in the RFG and Anti-dumping Question and Answer document. Finally, the final rule clarifies that each partner to a joint venture will be jointly and severally liable for the violations at a joint venture facility or by a joint venture operation. We received several comments on the proposal. Some commenters believe that
the Act does not authorize EPA to establish prohibitions against causing another person to commit a prohibitedact or causing the presence of nonconforming gasoline to be in the distribution system. These commenters believe that these prohibitions are a departure from the liability scheme under the existing fuels regulations and that they constitute double jeopardy by imposing liability for multiple violations for a single act. The commenters also believe that imposing liability for causing another person to commit a prohibited act extends the limits that Congress placed on liability under section 211 of the Act, since sections 211(d) and 211(k)(5) do not expressly mention imposing liability for causing another person to violate regulations. The commenter also noted that, had Congress intended for such actions to be prohibited, it could have expressly included such a prohibition in
section 211. This commenter cites section 211(g) as an example of a statutory provision with such a prohibition. One commenter said that, rather than clarify the presumptive liability scheme, the rule provides no guidance regarding what it means to cause someone to violate a prohibition or cause non-conforming gasoline to be in the distribution system. A commenter also stated that these proposed prohibitions are unnecessary, since EPA has issued violations to multiple parties under current fuels regulations.

EPA disagrees with the comment that the sulfur rule’s proposed liability scheme is a marked departure from the liability schemes typically found in the other fuels programs promulgated pursuant to section 211 of the Act and with the comment that the regulations constitute double jeopardy (the double jeopardy issue is addressed in the Response to Comment document). The majority of these programs, including the proposed sulfur rule, contain presumptive liability enforcement structures which impose liability on parties who, through their actions, could logically have caused the fuel nonconformity. The sulfur rule’s presumptive liability scheme is thus consistent with the liability schemes of typical prior fuels programs. While EPA
has issued notices of violations to multiple parties for violations under current fuels regulations, the Agency believes it is appropriate to clarify that the act of causing another party to violate the regulations is a prohibited act. Therefore, the regulatory language in the sulfur regulations explicitly
addresses this issue.

EPA also disagrees with the comment that this provision is inconsistent with Section 211(d) of the Act because Section 211(d) does not mention imposing liability for causing another person to violate the regulations promulgated under Section 211(c). For the reasons described above, EPA is adopting a provision in today’s regulations that prohibits causing another entity to violate the standards. This prohibition is a reasonable exercise
of EPA’s discretion under Section 211(c), and the penalty provision of Section 211(d) apply to violations of the prohibition. The fact that Section 211(d) does not specifically mention causing another person to violate the regulations is therefore irrelevant, such action is itself a violation of the regulations. Moreover, Section 211(d) does not mention any specific violations for which penalties may be assessed, but rather states generally that violations shall result in penalties. Thus, the absence of specific mention of causing another entity to violate the regulations is irrelevant, since all other specific prohibitions in regulations subject to Section 211(d) penalties are similarly
not mentioned.

The Agency also disagrees with the
comment that the Clean Air Act does not give EPA the authority to establish
causation violations under the sulfur rule. We believe that the Act gives us ample authority to categorize the sulfur rule’s causative acts, i.e., the causing of another party to commit a violation, and the causing of nonconforming gasoline to be present in the distribution system, as prohibited acts. Section 211(c) of the Act authorizes the Agency to promulgate regulations for the purpose of prohibiting or controlling the manufacture, introduction into commerce, sale, or offering for sale of
fuels or fuel additives where the fuel or
additive causes or contributes to air pollution which may reasonably be anticipated to endanger public health or welfare, or where the fuel or additive will impair to a significant degree the performance of emission control devices that are or will be in general use. Today’s gasoline sulfur rule is promulgated pursuant to this authority.

Section 211(c) gives EPA broad discretion to fashion regulations to control or prohibit the manufacture, introduction into commerce, sale, or offering for sale of fuels once the Agency has made the requisite findings regarding contribution to harmful air pollution or impairment of vehicle emissions control system performance. This includes the discretion to adopt


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reasonable regulatory provisions that are necessary and appropriate to ensure that the controls or prohibitions are effective. To effectively regulate sulfur in gasoline under section 211, it is necessary for the Agency to regulate the actions of those parties who do the manufacturing, introducing into commerce, and selling of gasoline subject to the sulfur requirements.

When one or several of these regulated parties causes another regulated party to violate the rule (or causes nonconforming gasoline to be present in the system), such an act could logically result in the high sulfur gasoline contributing to harmful air pollution or to the impairment of
vehicle emission control device performance, which are the adverse impacts that legislative authority under section 211(c) was created to control. Examples of such upstream causative
acts include the scenario where a refiner produces high sulfur gasoline which it
sells to a distributor. That distributor then resells the nonconforming product to a variety of retail outlets which, in their turn, also violate the rule by selling the high sulfur gasoline to
owners of motor vehicles. Another example occurs where a distributor has created high sulfur gasoline by blending high sulfur blendstock into his gasoline.
This distributor then makes several different sales of this noncomplying product to a variety of retail outlets, which, in their turn, also violate the rule by selling the product to numerous motor vehicle owners. A third upstream
causation scenario could occur if several refiners happen to make nonconforming gasoline. Each then sells its nonconforming product to a different distributor, and a retail outlet which is a customer of both distributors, purchases some of the noncomplying gasoline from both distributors. The retailer then commits a violation by offering this product for sale to its

customers.

In some cases, an upstream action has more severe environmental impacts through causing a downstream violation
than would occur if the violation was corrected upstream. For example, a refiner may violate the sulfur regulations by shipping gasoline that exceeds the applicable standards when it leaves the refinery. If that violation is corrected before the gasoline reaches the retail outlets, the adverse environmental impacts could be mitigated or avoided. However, if the refiner’s violation is not corrected and ultimately causes a
number of violations of the standards at retail outlets, the environmental impact would be more severe, since high sulfur gasoline would be introduced into vehicles and impair catalyst performance. Therefore, it is reasonable to consider causing a downstream violation by another party to be a separate violation, since an upstream party’s actions can have more severe environmental consequences if they cause downstream parties to violate applicable requirements. For these reasons, it is reasonable to conclude that section 211(c) authorizes the Agency to prohibit and control such causative acts in order to ensure that gasoline ultimately introduced into vehicles
meets the low sulfur standards.

Our approach is also reasonable under section 211(c) even though section 211(c) does not expressly prohibit causing another party to violate standards adopted under this subsection. In fact, section 211(c) itself does not contain any express prohibitions, but rather provides EPA authority to regulate fuels and fuel additives, based on certain findings. In contrast, other provisions of section 211, such as section 211(g), do include express prohibitions against certain actions. Thus, under section 211(g), the specified actions are prohibited even in the absence of EPA adopting regulations to codify the prohibitions. In section 211(g), Congress indicated a clear intent to prohibit a specific action (misfueling), without requiring EPA to adopt regulations to implement that prohibition. However, section 211(c) authorizes EPA to establish regulations with certain controls and prohibitions, and, as described above, EPA has the discretion to adopt reasonable measures to ensure that the requirements of such regulations are met.

Moreover, the commenters’ assertion that this provision is inconsistent with
other subsections of section 211 of the Act is misplaced. First, while the sulfur standards do apply to all gasoline, including gasoline subject to the reformulated gasoline requirements, the sulfur standards are being adopted pursuant to EPA’s authority under section 211(c)(1), not under section 211(k). Therefore, section 211(k)(5)’s prohibitions, which describe actions that are violations of section 211(k), are
not relevant to the sulfur standards. In addition, the enumeration of specific prohibitions in section 211(k) does not mean that EPA may establish no other prohibited acts with respect to reformulated gasoline; rather, it simply
identifies certain actions that ‘‘shall be’’ violations of section 211(k), but does not preclude establishment of other appropriate prohibited acts pursuant to EPA’s authority under the Act.

The Agency also disagrees with the argument that the proposed causation violations under the sulfur rule would impose unjustifiable, multiple liability for the commission of a single prohibited act. The Agency is generally not in the best position to know the exact cause of a gasoline nonconformity since so many parties and actions are
involved with the sale and transfer of the gasoline. Therefore, for effective enforcement, we must have the ability to assert the liability of all the parties in the system who were connected with the nonconforming gasoline because they each could have caused the violation. Similarly, we must also have the ability to assert upstream liability
for the full number of downstream violations a party may be responsible for causing, even if the multiple downstream violations may all ultimately be found to stem from one gasoline sale or transfer on the part of the upstream party. The enforcement possibility exists that the separate downstream violations may each have stemmed from separate actions by that party.

Any party may rebut the presumption of liability for each asserted violation by establishing through affirmative
defenses that it did not cause the violation. Moreover, any party against
whom EPA institutes an enforcement action may raise equitable factors about its own conduct as part of settlement of
the violation enforcement action. In settling fuels matters, the Agency typically takes into account such matters as the volume of nonconforming product that a party was connected with, and the severity and the amount of proscribed activity that the party was actually involved with in causing the
violation. We do not believe that either the sulfur rule’s liability scheme or its future implementation will be arbitrary or unjustified.

To further alleviate commenters’ concern about potential liability for multiple violations under the sulfur rule, we want to clarify that the Agency does not ordinarily attempt to collect separate penalties from an entity for the array of possible standard violations ( e.g., both for the manufacturing and the selling of noncomplying product), that a party might be liable for in respect to the same gasoline. In addition, we do not intend to seek penalties from a single party for violating regulatory standard requirements while also seeking penalties for that party’s causing of other entities to violate regulatory standard requirements, where both violations involve the same gasoline, unless very unusual circumstances exist which would warrant such action, such as egregious conduct on the part of the party.


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In a similar fashion, we do not expect to collect penalties from one party for both types of causation violations for the same amount of gasoline under normal circumstances. A primary Agency purpose in defining the causation violations as two separate prohibited acts (i.e., causing another to commit a violation, and causing the presence of nonconforming product in the distribution system), was not to collect a double penalty, but to address
different scenarios of evidence collection. For example, if the Agency
finds a sulfur rule standard violation in a sample from a retail outlet supplied by a certain distributor, but we do not have a nonconforming sample from the distributor, the evidence would most easily permit us to assert that the distributor was responsible for causing
the retailer violation that we do have
evidence for. It is reasonable for us to assert the causation violation against the distributor in spite of our lack of a sample from the distributor, because any distributor who transfers gasoline to a retailer, which gasoline is found to be noncompliant, could logically have caused the noncompliance of the gasoline when it was under the distributor’s control, such as by blending high sulfur blendstock into the gasoline.

On the other hand, if we have a violation sample from a distributor, but no samples from its downstream customers, we may assert that the distributor caused the presence of nonconforming gasoline in the distribution system, rather than assert that the distributor caused another party to sell nonconforming product, since we don’t have a nonconforming sample from another party’s facility. It would be
reasonable for us to assert that the distributor caused the presence of nonconforming gasoline in the distribution system since we do have a sample of nonconforming gasoline from the distributor, and provided also that
there is evidence that the distributor had sold, transferred, etc. this product
to downstream customers.

In summary, the Agency intends to enforce the liability scheme of the sulfur
rule in the same reasonable manner that we have enforced the similar liability schemes in our prior fuels regulations. This does not include attempting to penalize a party for multiple variations of noncompliance in regard to the same gasoline unless unusual circumstances make such action appropriate.

I. How Will Compliance With the Sulfur
Standards Be Determined?

We have often used a variety of evidence to establish non-compliance with the requirements imposed under our current fuels regulations. Test results of the content of gasoline have been used to establish violations, both in situations where the sample has been taken from the facility at which the violation occurred, and where the sample has been obtained from other parties’ facilities when such test results have had probative value of the gasoline’s characteristics at points upstream or downstream. The Agency has also commonly used documentary evidence to establish non-compliance or a party’s liability for non-compliance. Typical documentary evidence has included PTDs identifying the gasoline as inappropriate for the facility it is being delivered to, or identifying partieshaving connection with the noncomplying gasoline.

EPA proposed that compliance with
the sulfur standards would be
determined based on the sulfur level of the gasoline, as measured using the regulatory testing methodologies. We further proposed that any evidence from any source or location could be used to establish the gasoline sulfur level, provided that such evidence is relevant
to whether the level would have been in compliance if the regulatory sampling and testing methodology had been correctly performed. In today’s action, EPA is adopting the proposed regulatory provision.

Several commenters interpreted this proposed language as evidencing the Agency’s intent to make all evidence, including evidence not derived from regulatory test methods, equal in probative value to that from the regulatory test methods. One commenter also stated that the proposed provision is inconsistent with other parts of the proposal because it undercuts the benefits of having clearly defined regulatory test methodologies. EPA disagrees that the regulatory language indicates such an intent, or has such an effect. The regulations provide that compliance with the standards is to be determined using specified test methodologies. While other information may be used, including test results using different test methods, such other information may only be used if it is relevant to determining whether the sulfur level would meet applicable standards had compliance been properly measured using the specified test methodologies. Thus, the regulation adopted today does not result in a situation where any and all evidence carries equal weight in an enforcement action. In fact, the regulation establishes the regulatory test method as the standard against which other evidence is measured. Moreover, since any evidence other than regulatory test results must be relevant to compliance using the test method, EPA disagrees
with the commenter who stated that the validity of the sulfur standards can be challenged in any enforcement action because neither EPA nor regulated entities will be able to rely on measurements taken using the regulatory test methods. Rather than causing more confusion regarding compliance with the standard, this provision clarifies that the regulatory test method defines compliance, since other evidence can only be used if it relates to compliance using that test
method.

The following is an example of how the Agency believes evidence of standard non-compliance not based on regulatory test results might be used for compliance purposes under today’s rule provisions. Under a first scenario, the Agency might not have sulfur results derived from regulatory test methods for a certain amount of gasoline sold by a terminal, yet the terminal’s own test results, based on testing using methods other than those specified in the regulations, show an exceedance of the sulfur standard. Under the requirements of today’s rule, the evidence from the non-regulatory test method could only be used to establish noncompliance if
the terminal’s test results are relevant to the determination of the gasoline’s
sulfur level that would have resulted if the regulatory test method had been used. Thus, the Agency would have to present evidence to link the results of
the alternative test method to sulfur levels as measured using the regulatory
test method.

Another commenter has suggested that, if the Agency decides to finalize a ‘‘credible evidence’’ provision, it use the language in the current RFG regulations which establishes a presumption that the regulatory testing methods prevail, except in exceptional circumstances. Other commenters also opposed the proposed provision in part because it
differs from that in EPA’s current fuels regulations. As described above, EPA believes that the provision adopted today does not undercut the importance of the regulatory testing methodologies, since other evidence may be used only as relevant to compliance as measured using the regulatory methods. In addition, as is consistent with the RFG scheme, EPA believes it is appropriate
to use such other evidence even in some circumstances where test results using the regulatory test methods do exist, and the provision adopted today clarifies
this. EPA also notes that it intends to undertake rulemaking in the near future to revise the current fuels regulations to


### 6816 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

154 The commenter references section 211(k)(5) as support for its assertion, but quotes language from section 211(k)(4). EPA assumes that the commenter intended to cite section 211(k)(4) rather than section 211(k)(5). include the same language for use of other evidence as adopted today in the
final sulfur rule.

The provision adopted today also clarifies that any probative evidence obtained from any source or locationmay be used to establish noncompliance with requirements other than the sulfur standards, such as recordkeeping requirements and requirements to properly calculate sulfur credits and averages, as well as to establish which parties have facility control or some other basis for liability for sulfur rule non-compliance. Since proof of these elements is not predicated on establishing sulfur levels, whether or not regulatory test methods are used is not significant. Therefore commenters’
concern about the use of other evidence undercutting the primacy of the regulatory test methods is not germane to this part of the regulation which is
not directed toward standards. This provision is being included in the final sulfur rule to clarify that this rule, as is consistent with our interpretation of our other fuels rules, contemplates the full
use of all relevant evidence to establish
non-standard violations and rule liability.

EPA disagrees with the commenters who stated that EPA lacks authority under the Clean Air Act to permit the use of any evidence of non-compliance
of the sulfur standards other than test results using the regulatory test
methods. One commenter notes that the only explicit reference in the Act to the
use of ‘‘credible evidence’’ is in section 113(e), which applies only to stationary sources, and that neither section 211 nor
section 205 mention ‘‘credible evidence.’’ Finally, the commenter states that the proposed provision is
inconsistent with the directive of section 211(k) that EPA determine appropriate measures of and methods for ascertaining the emissions of air pollutants.

EPA disagrees with the comments asserting that the Agency lacks authority to promulgate this provision. While section 113(e) does refer to ‘‘credible evidence,’’ that provision is not relevant to EPA’s action today. Moreover, the absence of the explicit use of the term
‘‘credible evidence’’ in sections 205 and 211 does not compel a conclusion that EPA lacks authority to allow the
consideration of relevant evidence in determining compliance with the sulfur
standards. EPA believes that section 211(c) provides sufficient authority to adopt such a provision. Section 211(c) authorizes the Agency to promulgate regulations for the purpose of prohibiting or controlling the manufacture, introduction into commerce, sale, or offering for sale of
fuels or fuel additives where the fuel or
additive causes or contributes to air pollution which may reasonably be anticipated to endanger public health or welfare, or where the fuel or additive will impair to a significant degree the performance of emission control devices that are or will be in general use. As
described in other sections of this preamble and in the RIA, today’s regulation is promulgated pursuant to this authority. Section 211(c) gives EPA broad discretion to fashion regulations to control or prohibit the manufacture, introduction into commerce, sale, or offering for sale of fuels once the Agency has made the requisite findings regarding contribution to harmful air pollution or impairment of vehicle emissions control system performance. This includes the discretion to adopt reasonable regulatory provisions that are necessary and appropriate to ensure that the controls or prohibitions are effective
and can be enforced.

To ensure the effectiveness and the ability to adequately enforce the sulfur standards, it is reasonable for EPA to
consider evidence other than actual test results using the regulatory test method,
where such evidence can be related to the test results. As described above, test results using the regulatory test method
are often not available. In such circumstances, it is reasonable to consider other evidence of compliance, such as test results using other methods or commercial documents, if such
evidence can be shown to be relevant to determining whether the gasoline would meet the standard if tested using the regulatory methods. This provision would not permit the use of other
evidence that is not relevant to such a determination, and is therefore reasonably limited to allow for effective enforcement, without creating uncertainty about compliance.

Finally, EPA disagrees with the
commenter’s assertion that this provision is inconsistent with section 211(k). First, while the sulfur standards do apply to all gasoline, including gasoline subject to the reformulated gasoline requirements, the sulfur standards are being adopted pursuant to EPA’s authority under section 211(c)(1), not under section 211(k). In any case, the directive of section 211(k)(4) that EPA determine through regulation appropriate measures of and methods for ascertaining the emissions of air pollutants explicitly applies only for purposes of section 211(k), and applies for determining the emissions levels of VOCs and toxic air pollutants from baseline vehicles when operating on baseline gasoline, as defined by section 211(k). Thus, the commenter’s reference to section 211(k)(4) as inconsistent with the provision adopted today is misplaced, particularly in light of the limited applicability of the language in section 211(k)(4). 154

As described in the NPRM, the Agency frequently uses a variety of evidence to establish compliance with fuel programs’ regulatory requirements and liability for non-compliance. Such
evidence has included test results obtained from a variety of sources, including bills of lading, delivery records, manifests, and other commercial documents. The compliance determination provisions included in today’s final rule are created to provide the most effective Agency capability to enforce the rule’s requirements.

VII. Public Participation

A wide variety of interested parties participated in the rulemaking process
that culminates with this final rule. The formal comment period and four public hearings associated with the NPRM provided additional opportunities for public input. EPA also met with a variety of stakeholders, including environmental and public health organizations, oil company representatives, auto company representatives, emission control equipment manufacturers, and states at various points in the process.

We have prepared a detailed Response to Comments document that
describes the comments received on the NPRM and presents our response to each of these comments. The Response
to Comments document is available in
the docket for this rule and on the Office of Mobile Sources internet home page. Comments and our responses are also included throughout this preamble for several key issues.

VIII. Administrative Requirements

A. Administrative Designation and Regulatory Analysis

Under Executive Order 12866 (58 FR 51735, Oct. 4, 1993), the Agency is required to determine whether this regulatory action would be ‘‘significant’’ and therefore subject to review by the Office of Management and Budget (OMB) and the requirements of the
Executive Order. The order defines a ‘‘significant regulatory action’’ as any regulatory action that is likely to result in a rule that may:


### 6817 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

155 The Final RFA is contained in Chapter 8 of the Regulatory Impact Analysis. 156 Report of the Small Business Advocacy Panel on Tier 2 Light-Duty Vehicle and Light-Duty Truck Emission Standards, Heavy-Duty Gasoline Engine Standards, and Gasoline Sulfur Standards, October

1998. • Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;

• Create a serious inconsistency or
otherwise interfere with an action taken or planned by another agency;

• Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or,

• Raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles
set forth in the Executive Order.

Pursuant to the terms of Executive Order 12866, EPA has determined that this final rule is a ‘‘significant regulatory action’’ because the vehicle standards, gasoline sulfur standards, and other regulatory provisions, if implemented,
would have an annual effect on the economy in excess of $100 million. Accordingly, we have prepared a Final Regulatory Impact Analysis (RIA) which
is available in the docket for this rulemaking and at the internet address
listed under ADDRESSES above. This
action was submitted to the Office of Management and Budget (OMB) for review as required by Executive Order 12866. Any written comments from OMB on today’s action and any responses from EPA to OMB comments are in the public docket for this rulemaking.

B. Regulatory Flexibility

The Regulatory Flexibility Act, 5 U.S.C. 601–612, was amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), Public Law 104–121, to ensure that concerns regarding small entities are adequately considered during the development of new regulations that affect them. EPA has identified industries subject to this rule and has provided information to, and received comment from, small entities and representatives of small
entities in these industries. We have prepared a Final Regulatory Flexibility Analysis (RFA) to evaluate the economic impacts of today’s proposal
on small entities. 155 The key elements of
the RFA include:

• The number of affected small entities;

• The projected reporting, record keeping, and other compliance requirements of the proposed rule, including the classes of small entities that would be affected and the type of professional skills necessary for preparation of the report or record;

• Other federal rules that may duplicate, overlap, or conflict with the proposed rule; and • Any significant alternatives to the proposed rule that accomplish the stated objectives of applicable statutes and that minimize significant economic impacts of the proposed rule on small

entities.

The Agency convened a Small Business Advocacy Review Panel (the Panel) under section 609(b) of the Regulatory Flexibility Act as added by SBREFA. The purpose of the Panel was
to collect the advice and recommendations of representatives of small entities that could be affected by today’s proposed rule and to report on
those comments and the Panel’s findings as to issues related to the key elements of the Regulatory Flexibility Analysis under section 603 of the Regulatory Flexibility Act. The report of the Panel has been placed in the docket for this rulemaking. 156

The contents of today’s final rule and the Final Regulatory Flexibility Analysis
reflect the recommendations in the Panel’s report. We summarize our
outreach to small entities and our responses to the recommendations of
the Panel below.

1. Potentially Affected Small Businesses

The Regulatory Flexibility Analysis
identifies small businesses from the industries in the following table as subject to the provisions of today’s rule:



### TABLE 

### VIII.1.—I NDUSTRIES 

### C ONTAINING 

### S MALL 

### B USINESSES 

### P OTENTIALLY 

### A FFECTED BY 

### TODAY

### ’ S 

### R ULE

Industry NAICS

a codes SIC b codes Defined by SBA as a small business if:

c

Motor Vehicle Manufacturers ....................................... 336111 3711 < 1000 employees.

336112

336120 Alternative Fuel Vehicle Converters ............................. 336311 3592 < 500 employees.

541690 8931 336312 3714 < 750 employees. 422720 5172 < 100 employees. 454312 5984 7549 < $5 million annual sales.

811198 8742

541514 Independent Commercial Importers of Vehicles and

Vehicle Components. 811112 7533

7549 < $5 million annual sales.

811198 8742

541514 Petroleum Refiners ....................................................... 324110 2911 < 1500 employees. Petroleum Marketers and Distributors .......................... 422710 5171 5172 < 100 employees.

422720

a North American Industry Classification System.

b Standard Industrial Classification system.

c According to SBA’s regulations (13 CFR 121), businesses with no more than the listed number of employees or dollars in annual receipts are considered ‘‘small entities’’ for purposes of a regulatory flexibility analysis.

The Final RFA identifies about 15 small petroleum refiners, several hundred small petroleum marketers, and about 15 small certifiers of covered vehicles (belonging to the other categories in the above table) that would be subject to the rule.


### 6818 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

157 The information collection requirements

associated with the amendments to the requirements for vehicle certification are contained in the Information Collection Request entitled ‘‘Amendments to the Reporting and Recordkeeping Requirements for Motor Vehicle Certification Under the Tier 2 Rule’’, OMB No. 2060–0114, EPA ICR #

783.40. 2. Small Business Advocacy Review Panel and the Evaluation of Regulatory
Alternatives

The Small Business Advocacy Review Panel was convened by EPA on August 27, 1998. The Panel consisted of representatives of the Small Business Administration (SBA), the Office of Management and Budget (OMB), and EPA. During the development of the proposal, EPA and the Panel were in contact with representatives from the small businesses that would be subject to the provisions of the rule. In addition to verbal comments from industry noted by the Panel at meetings and teleconferences, we received written
comments from each of the affected industry segments or their representatives. These comments, alternatives suggested by the Panel to mitigate adverse impacts on small businesses, and issues the Panel requested EPA take additional comment on are contained in the report of the
Panel and are summarized below. Today’s final rule incorporates the major recommendations of the Panel.

Fuel-Related Small Business Issues

Most of the small refiners stated that if they were required to achieve 30 ppm sulfur levels on average with an 80 ppm per-gallon cap without some regulatory relief, they would be forced out of business. Thus, the Panel devoted much attention to regulatory alternatives to
address this concern. Most small refiners strongly supported delaying mandatory compliance for their facilities. On the other hand, most small refiners stated that a phase-in of gasoline sulfur standards would not behelpful because it would be more costeffective for them to install the maximum technology required for the most stringent sulfur levels that would ultimately be imposed.

The Society of Independent Gasoline Marketers of America (SIGMA)
commented that EPA should consider giving relief not only to refiners that
meet the SBA definition of small refiner but also to refineries with relatively small production capacity that are owned by large refining companies. This was because a refinery with a small production capacity would operate essentially as an SBA-defined small
refiner would. SIGMA also noted that small gasoline marketers would be affected by the closure of any refinery with small production capacity, whether it was owned by a large company or an SBA-defined small refining company.

The Panel recommended that small refiners be given a four to six year period of relief during which less stringent gasoline sulfur requirements would apply. The Panel also advised that EPA specifically request comment on an alternative duration of ten years for the relief period. Small refiners would be assigned interim sulfur standards during this relief period based on their current individual refinery sulfur levels. Following this relief period, small refiners would be required to meet the industry-wide standard, although temporary hardship relief would be available on a case-by-case
basis. The Panel concluded that additional time provided to small refiners before compliance with the industry-wide standard was required would allow (1) new sulfur-reduction technologies to be proven-out by larger refiners, (2) the costs of advanced technology units to drop as the volume of their sales increases, (3) industry engineering and construction resources to be freed-up, and (4) the acquisition of the necessary capital by small refiners.

The Panel also concluded that adding gasoline sulfur to the fuel parameters already being sampled and tested by gasoline marketers would likely result in little, if any, additional burden. Therefore, the Panel did not recommend any special provision for gasoline
marketers.

EPA’s final action on this issue closely follows the Panel’s
recommendations. You can find a description of the small refiner provisions of today’s final rule in
Section IV.C.2. above. Comments and our responses on related issues are collected in the Response to Comments
document.

Vehicle-Related Small Business Issues

Independent commercial importers of vehicles (ICIs) suggested that the new emissions standards be phased-in with the phase-in schedule based on the
small vehicle manufacturer’s annual production volume. Secondly, the ICIs requested that small testing laboratories be permitted to use older technology dynamometers than proposed for use by the Agency. Finally, the ICIs
commented that the certification process should be waived for certain foreign vehicles. Small-volume vehicle manufacturers (SVMs) stated that a phase-in of Tier-2 emissions standards is essential. They further stated that SVMs should not be required to comply until the end of the phase-in period, which should not be before model year
2007. The SVMs also stated that a caseby-case hardship relief provision should be provided for their members. SVMs requested that a credit program be established with incentives for larger manufacturers to make credits available to SVMs in meeting their compliance goals.

Based on the above comments, the
Panel advised that EPA consider several alternatives, individually or in combination, for the potential relief that they might provide to small certifiers of
vehicles.

The Final Regulatory Flexibility Analysis evaluates the financial impacts of the proposed vehicle standards and
fuel controls on small entities. EPA believes that the regulatory alternatives incorporated in today’s final rule will provide substantial relief to small business from the potential adverse economic impacts of complying with today’s proposed rule.

C. Paperwork Reduction Act

The information collection requirements (ICRs) associated with today’s rule belong to two distinct categories: (1) those that pertain to
amendments to the vehicle certification requirements, and (2) those that pertain to requirements for the control of gasoline sulfur content. These information collection requirements are contained in two separate ICR documents according to the category to which they belong.

The ICR in this final rule that pertains
to the amendments to the vehicle certification requirements has been submitted for approval to the Office of Management and Budget (OMB) under
the Paperwork Reduction Act, 44 U.S.C.

3501 et seq. Copies of this ICR 157 can be obtained from Sandy Farmer, Office of Environmental Information, Collections Strategy Division, U.S. Environmental Protection Agency (Mail Code 2822), 401 M Street, SW, Washington, D.C. 20460, or by calling (202) 260–2740. Please refer to ICR #783.40 in any correspondence. Copies may also be downloaded from the

internet at http://www.epa.gov/icr.

The ICR in this final rule that pertains to the requirements for the control of gasoline sulfur will be submitted for approval to the Office of Management and Budget (OMB) under the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq. The submission to OMB of the ICR
document that contains this ICR and its availability to the public will be announced in a subsequent Federal Register notice.


### 6819 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

158 These ICRs will become effective on the date that model year 2001 vehicles are introduced into commerce. EPA assumes that September 1, 2000 is the earliest date that model year 2001 vehicles will

be marketed.

159 Assuming model year 2004 vehicles are

introduced into commerce on this date. 160 A refiner can petition EPA for an extension of the small refiner provisions beyond January 1, 2008, based on hardship.

161 The information collection requirements associated with the proposed gasoline sulfur control program are contained in the Information Collection Request that accompanied the Tier 2 NPRM which is entitled ‘‘Recordkeeping and Reporting Requirements Regarding the Sulfur Content of Motor Vehicle Gasoline Under the Tier 2 Proposed Rule’’, ICR #1907.01. Copies of this ICR can be

obtained as discussed earlier in this section. The Agency may not conduct or sponsor an information collection, and a person is not required to respond to a request for information unless the information collection request displays a currently valid OMB control number.
The OMB control numbers for EPA’s regulations are listed in 40 CFR Part 9 and 48 CFR Chapter 15. The OMB
control numbers for the information collection requirements in this rule will
be listed in an amendment to 40 CFR part 9 in a subsequent Federal Register notice after OMB approves the ICRs.

The Paperwork Reduction Act stipulates that ICR documents estimate the burden of activities required of regulated parties within a three year time period. Consequently, the ICR documents associated with today’s final
rule contain burden estimates for the activities that will be required under the first three years of the program.

ICRs Pertaining to the Amendments to Vehicle Certification Requirements: The
information collection burden to vehicle
certifiers associated with the
amendments to the vehicle certification requirements in today’s notice pertain to the fleet-average NO X standard and emission credits provisions. These requirements are very similar to those under the voluntary National Low Emission Vehicle (NLEV) program, which includes a fleet-average standard for nonmethane hydrocarbon organic gases (NMOG) and associated emission credits provisions. The hours spent annually by a given vehicle certifier on
the information collection activities associated with the these recordkeeping and reporting requirements depends upon certifier-specific variables, including: the scope/variety of their product line as reflected in the number of test groups and strategy used to comply with the fleet-average NO X standard, the extent they utilize emissions credits provisions, and whether they opted into the NLEV program. Vehicle certifiers that use the provisions for early banking of emission credits will be subject to the associated information collection requirements as early as September 1, 2000. 158 All vehicle certifiers will be required to comply with the information collection requirements associated with the
amendments to the vehicle certification program beginning September 1,

2003. 159 The ICR document for the
amendments to the vehicle certification program in this final rule provides
burden estimates for all of the
associated information collection requirements. The total information
collection burden associated with the
amendments to the vehicle certification requirements is estimated at 8,406 hours and $567,217 annually for the certifiers of light-duty vehicles, medium-duty passenger vehicles, and light-duty
trucks.

ICRs Pertaining to the Requirements for Gasoline Sulfur Control: The
information collection burden to gasoline refiners, importers, marketers, distributors, retailers and wholesale purchaser-consumers (WPCs), and users of research and development (R&D) gasoline pertain to the gasoline sulfur control program in today’s rule. The scope of the recordkeeping and reporting requirements for each regulated party, and therefore the cost to that party, reflects the party’s opportunity to create, control, or alter the sulfur content of gasoline. As a result, refiners and importers have significant requirements, which are necessary both for their own tracking, and that of downstream parties, and for
EPA enforcement. Parties downstream from the gasoline production or import point, such as retailers, have minimal burdens that are primarily associated
with the transfer and retention of product transfer documents. Many of the reporting and recordkeeping requirements for refiners and importers regarding the sulfur content of gasoline currently exist under EPA’sReformulated Gasoline (RFG) and AntiDumping programs. The ICR for the RFG program covered start up costs associated with reporting gasoline sulfur content under the RFG program. Consequently, much of the cost of the information collection requirements under the gasoline sulfur control program has already been accounted for under the RFG program ICR. In addition, many of the information
collection burdens associated with the sulfur program are the result of provisions designed to provide refiners with flexibility in demonstrating compliance with the sulfur standards in the early years of the program, such as the credit trading and small refiner

programs.

The information collection requirements under the sulfur control program evolve over time as the program is phased-in. Beginning July 1, 2000, certain requirements apply to parties that voluntarily opt to generate credits for early sulfur reduction under the average banking and trading (ABT) provisions. Many of the requirements do not become applicable until the beginning of the sulfur control program on October 1, 2003, when all refiners are required to meet the sulfur standards. The information collection requirements under the sulfur control program become stable after January 1, 2008, when the optional small refiner provisions expire. 160

The ICR document for the sulfur control program in this final rule will provide burden estimates for the activities required under the first three years of the program, from July 1, 2000, through June 30, 2003. The burden associated with activities required after June 30, 2003, will be estimated in later ICRs. The initial ICR for the gasoline sulfur control program, however, will provide a qualitative characterization of all of the required activities and
associated burdens for the various regulated parties as they develop, and until they become stable after January 1,

2008.

In the ICR associated with the NPRM for this final rule, we estimated that the
total burden of the information collection requirements that would be applicable during the first three years of the proposed gasoline sulfur control program would be 42,479 hours and $2,149,865 annually. 161 Annual burden estimates for the various regulated entities under the initial three year period of the gasoline sulfur control program were also provided in the
NPRM ICR as follows:

• Refiners: 31,231 hours; $1,879,822.

• Importers: 40 hours; $2,067.

• Pipelines: 85 hours; $2,785.

• Terminals: 1,700 hours; $55,700.

• Truckers: 3,333 hours; $118,000.

• Retailers/WPCs: 6,087 hours; $91,298.

• R&D Gasoline Users: 3 hours; $193.
We received few comments on the ICR burden estimates in the proposed sulfur rule. Most regulated parties have been fulfilling reporting, recordkeeping and testing requirements under the reformulated and conventional gasoline regulations. The only negative
comments we received related to the batch testing for sulfur content and sample retention for conventional gasoline. We believe the estimated cost of complying with these requirements is somewhat higher than the actual


### 6820 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

burdens industry will realize. The ICR for this final rule will be adjusted accordingly.

We estimate that there will be some additional costs and hourly burdens
over those estimated in the NPRM associated with certain changes made to the sulfur program from the NPRM to this final rule. In particular, this final rule includes a program which provides for relaxed standards in the early years of the program for refiners and importers who produce or import gasoline for use in certain states in the western U.S. This program requires some additional reporting and recordkeeping burdens for those refiners and importers who participate in the program, since they will be required to submit an application for the program, including a baseline for purposes of establishing their sulfur standard. This program requires gasoline intended for use in the geographic area to be identified on product transfer documents and segregated from other gasoline in the distribution system. This final rule also includes provisions for trading sulfur allotments to provide refiners and importers additional flexibility in meeting the corporate pool average standards. This program requires additional reporting and recordkeeping to track allotment trading activity. In addition, the final rule requires small refiners to submit information regarding their crude oil capacity in order to qualify for the small
refiner standards under the rule. Small refiners are also required to submit reports of their progress toward compliance with the sulfur standards.
The additional total annual cost and hourly burden over the first three years of the program, as a result of changes made to the program in the final rule,
are estimated to add less than one percent to the overall burden estimates
contained in the NPRM ICR for the sulfur control program.

Total Burden of the ICRs: In the NPRM, we estimated that the total burden of the recordkeeping and reporting requirements associated with the proposed vehicle certification and gasoline sulfur control requirements would be 50,840 hours and $2,714,037 annually over the first three years that these requirements would be in effect.
In the ICR document for this final rule
which covers the ICRs for the vehicle certification program, the burden estimates were increased by 45 hours and $3,045 over the burden estimates in
the NPRM ICR. This increase reflects changes from the NPRM in the final rule
associated the inclusion of the mediumduty passenger vehicles (MDPVs) under the program. As discussed above, we anticipate that changes to the ICR
document for this final rule which
covers the ICRs for the sulfur control program will have burden estimates less than one percent higher than the
estimates contained in the NPRM. Adding these increased costs to the burden estimates presented in the NPRM, we arrive at an estimate of the total burden of the recordkeeping and reporting requirements associated with the vehicle certification and gasoline sulfur control requirements in this final rule of less than 51,350 hours and $2,742,000 annually over the first three years that these requirements will be in
effect. These burden estimates will be more precisely stated in the forthcoming Federal Register notice which
announces the submission to OMB of
the ICR document for this final rule that
covers the ICRs for the sulfur control program and the availability of this ICR document to the public.

D. Intergovernmental Relations

1. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104– 4, establishes requirements for federal agencies to assess the effects of their regulatory actions on state, local, and tribal governments, and the private sector. Under section 202 of the UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with ‘‘federal mandates’’ that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more for any single year. Before promulgating
a rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and
consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective, or least
burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative thatis not the least costly, most costeffective, or least burdensome alternative if EPA provides an explanation in the final rule of why such an alternative was adopted.

Before we establish any regulatory requirement that may significantly or uniquely affect small governments, including tribal governments, we must develop a small government plan pursuant to section 203 of the UMRA. Such a plan must provide for notifying potentially affected small governments, and enabling officials of affected small governments to have meaningful and timely input in the development of our regulatory proposals with significant federal intergovernmental mandates. The plan must also provide for informing, educating, and advising small governments on compliance with the regulatory requirements.

This rule contains no federal mandates for state, local, or tribal governments as defined by the provisions of Title II of the UMRA. The rule imposes no enforceable duties on any of these governmental entities. Nothing in the rule would significantly or uniquely affect small governments.

EPA has determined that this rule contains federal mandates that may result in expenditures of more than $100 million to the private sector in any single year. EPA believes that today’s final rule represents the least costly, most cost-effective approach to achieve the air quality goals of the rule. The cost-benefit analysis required by the
UMRA is discussed in Section IV.D.
above and in the Draft RIA. See the ‘‘Administrative Designation’’ and Regulatory Analysis’ section in today’s preamble (VIII.A.) for further information regarding these analyses.

2. Executive Order 13084: Consultation
and Coordination With Indian Tribal

Governments

Under Executive Order 13084, EPA may not issue a regulation that is not required by statute, that significantly or uniquely affects the communities of Indian Tribal governments, and that imposes substantial direct compliance costs on those communities, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by the tribal governments, or EPA consults with those governments. If EPA complies by consulting, Executive Order 13084 requires EPA to provide to the Office of Management and Budget, in a separately identified section of the preamble to the rule, a description of the extent of EPA’s prior consultation with representatives of affected tribal governments, a summary of the nature of their concerns, and a statement supporting the need to issue the regulation. In addition, Executive Order 13084 requires EPA to develop an effective process permitting
elected officials and other representatives of Indian tribal governments ‘‘to provide meaningful and timely input in the development of regulatory policies on matters that significantly or uniquely affect their

communities.’’

Today’s rule does not significantly or uniquely affect the communities of Indian Tribal governments. The motor


### 6821 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

vehicle emissions, motor vehicle fuel, and other related requirements for private businesses in today’s rule would have national applicability, and thus would not uniquely affect the
communities of Indian Tribal Governments. Further, no circumstances specific to such communities exist that would cause an impact on these communities beyond those discussed in the other sections of today’s document. Thus, EPA’s conclusions regarding the impacts from the implementation of today’s rule discussed in the other sections of this preamble are equally applicable to the communities of Indian Tribal governments. Accordingly, the requirements of section 3(b) of Executive Order 13084 do not apply to
this rule.

3. Executive Order 13132 (Federalism)

Executive Order 13132, entitled ‘‘Federalism’’ (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure ‘‘meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.’’ ‘‘Policies that have federalism implications’’ is defined in
the Executive Order to include regulations that have ‘‘substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.

Under Section 6 of Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed regulation. EPA also may not issue a regulation that has federalism implications and that preempts State law, unless the Agency consults with State and local officials early in the process of developing the proposed regulation.

Section 4 of the Executive Order contains additional requirements for rules that preempt State or local law,
even if those rules do not have federalism implications (i.e. , the rules
will not have substantial direct effects on the States, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government). Those requirements include providing all
affected State and local officials notice and an opportunity for appropriate participation in the development of the regulation. If the preemption is not based on express or implied statutory authority, EPA also must consult, to the extent practicable, with appropriate State and local officials regarding the
conflict between State law and Federally protected interests within the agency’s area of regulatory responsibility.

This final rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. This rule adopts
national emissions standards for certain categories of motor vehicles and national standards to control gasoline sulfur. The requirements of the rule will be enforced by the federal government at the national level. Thus, the requirements of section 6 of the Executive Order do not apply to this rule. Although section 6 of Executive Order 13132 does not apply to this rule,
EPA did consult with State and local officials in developing this rule. In addition, EPA provided state and local officials an opportunity to comment on the proposed regulations. A summary of concerns raised by commenters, including state and local commenters, and EPA’s response to those concerns, is found in the Response to Comments document for this rulemaking.

This final rule preempts State and local controls or prohibitions respecting gasoline sulfur content, pursuant to Section 211(c)(4) of the Clean Air Act. The basis and scope of preemption is
described in Section IV.C.1.d of this notice. Although this rule was proposed before the November 2, 1999 effective date of Executive Order 13132, EPA provided State and local officials notice and an opportunity for appropriate participation when it published the proposed rule, as described above. Thus, EPA has complied with the requirements of section 4 of the
Executive Order.

E. National Technology Transfer and
Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (NTTAA), Section 12(d) of Public Law 104–113, directs EPA to use voluntary consensus standards in its regulatory activities unless it would be inconsistent with applicable law or otherwise impractical. Voluntary
consensus standards are technical standards ( e.g. , materials specifications, test methods, sampling procedures, and business practices) developed or adopted by voluntary consensus
standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.

This rule references technical standards adopted by the Agency through previous rulemakings. No new
technical standards are established in today’s rule. The standards referenced in today’s rule involve the measurement of gasoline fuel parameters and motor
vehicle emissions. The measurement standards for gasoline fuel parameters referenced in today’s proposal are all voluntary consensus standards. The
motor vehicle emissions measurement standards referenced in today’s rule are government-unique standards that were developed by the Agency through previous rulemakings. These standards have served the Agency’s emissions control goals well since their implementation and have been well accepted by industry. EPA is not aware of any voluntary consensus standards
for the measurement of motor vehicle emissions. Therefore, the Agency is using the existing EPA-developed
standards found in 40 CFR Part 86 for
the measurement of motor vehicle

emissions

F. Executive Order 13045: Children’s
Health Protection

Executive Order 13045, ‘‘Protection of
Children from Environmental Health Risks and Safety Risks’’ (62 FR 19885, April 23, 1997) applies to any rule that (1) is determined to be ‘‘economically significant’’ as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria,
section 5–501 of the Order directs the Agency to evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.

This rule is subject to the Executive Order because it is an economically significant regulatory action as defined by Executive Order 12866 and it concerns in part an environmental health or safety risk that we have reason to believe may have a disproportionate
effect on children.

This rulemaking will achieve significant reductions of various emissions from passenger cars and light trucks, primarily NO X , but also NMOG


### 6822 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

and PM. These pollutants raise concerns regarding environmental health or safety risks that EPA has reason to believe may have a disproportionate effect on children, such as impacts from ozone, PM and certain toxic air pollutants. See Section III of this preamble and the RIA
for a further discussion of these issues.

The effects of ozone and PM on
children’s health were addressed in detail in EPA’s rulemaking to establish the NAAQS for these pollutants, and we are not revisiting those issues here. We believe, however, that the emission reductions from the strategies established in this rulemaking will
further reduce air toxics and the related adverse impacts on children’s health. We will be addressing the issues raised by air toxics from motor vehicles and their fuels in a separate rulemaking that
we will initiate in the near future under section 202(l) of the Act. That rulemaking will address the emissions of hazardous air pollutants from vehicles and fuels, and the appropriate
level of control of HAPs from these

sources.

In this final rule, we have evaluated several regulatory strategies for reductions in emissions from passenger cars and light trucks. (See sections IV, V, and VI of this preamble as well as the RIA.) For the reasons described there, we believe that these strategies are preferable under the Clean Air Act to other potentially effective and reasonably feasible alternatives that we considered for purposes of reducing emissions from these sources (as a way of helping areas achieve and maintain the NAAQS for ozone and PM). Moreover, we believe that we have selected for proposal the most stringent and effective control reasonably feasible at this time, in light of the technology and cost requirements of the Act.

G. Congressional Review Act

The congressional review Act, 5 U.S.C. 801 et seq., as added by the Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the comptroller General
of the United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of representatives, and the Comptroller General of the United States prior to publication of the rule in
the Federal Register . This rule is a ‘‘major rule’’ as defined by 5 U.S.C. 804(2). IX. Statutory Provisions and Legal Authority

Statutory authority for the vehicle controls set in today’s final rule can be found in sections 202, 206, 207, 208, and 301 of the Clean Air Act (CAA), as amended, 42 U.S.C. sections 7521, 7525, 7541, 7542 and 7601.

Statutory authority for the fuel controls set in today’s final rule comes from section 211(c) of the CAA (42 U.S.C., section 7545(c)), which allows EPA to regulate fuels that either contribute to air pollution which endangers public health or welfare or which impair emission control equipment. Both criteria are satisfied for the gasoline sulfur controls we are establishing today. Additional supportfor the procedural and enforcementrelated aspects of the fuel’s controls in today’s final rule, including the record keeping requirements, comes from sections 114(a) and 301(a) of the CAA.

List of Subjects

40 CFR Part 80

Environmental protection, Air pollution control, Fuel additives, Gasoline, Imports, Incorporation by reference, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements.

40 CFR Part 85

Environmental protection, Administrative practice and procedure, Confidential business information, Imports, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements, Research,

Warranties.

40 CFR Part 86

Environmental protection, Administrative practice and procedure, Confidential business information, Incorporation by reference, Labeling, Motor vehicle pollution, Penalties, Reporting and recordkeeping requirements.

Dated: December 21, 1999.

Carol M. Browner,

Administrator.

For the reasons set forth in the preamble, parts 80, 85 and 86 of title 40, of the Code of Federal Regulations are
amended as follows:

PART 80—REGULATION OF FUELS
AND FUEL ADDITIVES

1. The authority citation for part 80
continues to read as follows:

Authority: Secs. 114, 211, and 301(a) of the Clean Air Act, as amended (42 U.S.C. 7414, 7545 and 7601(a)). 2. Section 80.2 is amended by removing and reserving paragraph (aa), adding paragraph (d), and revising paragraphs (h), (s) and (gg) to read as
follows:

§ 80.2 Definitions.

* * * * *

(d) Previously certified gasoline means gasoline or RBOB that previously
has been included in a batch for purposes of complying with the standards for reformulated gasoline, conventional gasoline or gasoline sulfur, as appropriate.

* * * * *

(h) Refinery means any facility, including but not limited to, a plant, tanker truck, or vessel where gasoline or diesel fuel is produced, including any facility at which blendstocks are combined to produce gasoline or diesel fuel, or at which blendstock is added to gasoline or diesel fuel.

* * * * *

(s) Gasoline blending stock, blendstock, or component means any liquid compound which is blended with other liquid compounds to produce gasoline.

* * * * *

(gg) Batch of gasoline means a quantity of gasoline that is homogeneous with regard to those properties that are specified for conventional or reformulated gasoline.

* * * * *

3. Section 80.46 is amended by revising paragraphs (a) and (h) to read
as follows:

§ 80.46 Measurement of reformulated gasoline fuel parameters.

(a) Sulfur. Sulfur content of gasoline and butane must be determined by use of the following methods:

(1) The sulfur content of gasoline must be determined by use of American Society for Testing and Materials (ASTM) standard method D 2622–98,
entitled ‘‘Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry.’’

(2) The sulfur content of butane must be determined by the use of ASTM standard method D 3246–96, entitled
‘‘Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry.’’

* * * * *

(h) Incorporations by reference. ASTM standard methods D 2622–98, D
3246–96, D 3606–92, D 1319–93, D 4815–93, and D 86–90 with the exception of the degrees Fahrenheit figures in Table 9 of D 86–90, are incorporated by reference. These


### 6823 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Dr., West Conshohocken, PA 19428. Copies may be inspected at the Air Docket Section (LE–131), room M– 1500, U.S. Environmental Protection Agency, Docket No. A–97–03, 401 M Street, SW., Washington, DC 20460, or at the Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC.

4. Subpart H is added to part 80 to
read as follows:

Subpart H—Gasoline Sulfur

General Information

Sec. 80.180 [Reserved] 80.185 [Reserved] 80.190 Who must register with EPA under the sulfur program?

Gasoline Sulfur Standards

80.195 What are the gasoline sulfur standards for refiners and importers? 80.200 What gasoline is subject to the sulfur standards and requirements? 80.205 How is the annual refinery or importer average and corporate pool average sulfur level determined? 80.210 What sulfur standards apply to gasoline downstream from refineries and importers? 80.211 [Reserved] 80.212 What requirements apply to oxygenate blenders? 80.213–80.214 [Reserved]

Geographic Phase-In Program
80.215 What is the scope of the geographic phase-in program? 80.216 What standards apply to gasoline produced or imported for use in the

GPA? 80.217 How does a refiner or importer apply for the GPA standards? 80.218 [Reserved] 80.219 Designation and downstream requirements for GPA gasoline.

80.220 What are the downstream standards for GPA gasoline?

Hardship Provisions

80.225 What is the definition of a small

refiner? 80.230 Who is not eligible for the hardship provisions for small refiners? 80.235 How does a refiner obtain approval

as a small refiner? 80.240 What are the small refiner gasoline

sulfur standards? 80.245 How does a small refiner apply for

a sulfur baseline?

80.250 How is the small refiner sulfur

baseline and volume determined? 80.255 Compliance plans and
demonstration of commitment to produce low sulfur gasoline. 80.260 What are the procedures and requirements for obtaining a hardship

extension? 80.265 How will the EPA approve or disapprove a hardship extension application? 80.270 Can a refiner seek temporary relief from the requirements of this subpart?

Allotment Trading Program
80.275 How are allotments generated and
used?

Averaging, Banking and Trading (ABT) Program—General Information

80.280 [Reserved] 80.285 Who may generate credits under the ABT program? 80.290 How does a refiner apply for a sulfur
baseline?

ABT Program—Baseline Determination
80.295 How is a refinery sulfur baseline
determined? 80.300 [Reserved]

ABT Program—Credit Generation
80.305 How are credits generated during the time period 2000 through 2003? 80.310 How are credits generated beginning

in 2004?

ABT Program—Credit Use

80.315 How are credits used and what are
the limitations on credit use? 80.320 [Reserved] 80.325 [Reserved]

Sampling, Testing and Retention Requirements for Refiners and Importers
80.330 What are the sampling and testing requirements for refiners and importers? 80.335 What gasoline sample retention requirements apply to refiners and importers? 80.340 What standards and requirements apply to refiners producing gasoline by blending blendstocks into previously certified gasoline (PCG)? 80.345 [Reserved]
80.350 What alternative sulfur standards and requirements apply to importers who transport gasoline by truck? 80.355 [Reserved]

Recordkeeping and Reporting Requirements

80.360 [Reserved] 80.365 What records must be kept? 80.370 What are the sulfur reporting requirements? 80.371–80.373 [Reserved]

Exemptions
80.374 What if a refiner or importer is unable to produce gasoline conforming to the requirements of this subpart? 80.375 What requirements apply to California gasoline? 80.380 What are the requirements for obtaining an exemption for gasoline used for research, development or testing purposes?

Violation Provisions
80.385 What acts are prohibited under the gasoline sulfur program? 80.390 What evidence may be used to determine compliance with the prohibitions and requirements of this subpart and liability for violations of this subpart?

80.395 Who is liable for violations under the gasoline sulfur program? 80.400 What defenses apply to persons

deemed liable for a violation of a prohibited act? 80.405 What penalties apply under this subpart?

Provisions for Foreign Refiners With
Individual Sulfur Baselines

80.410 What are the additional requirements for gasoline produced at foreign refineries having individual small refiner sulfur baselines, foreign refineries granted temporary relief under § 80.270, or baselines for generating credits during 2000 through 2003?

Attest Engagements

80.415 What are the attest engagement requirements for gasoline sulfur compliance applicable to refiners and importers?

Subpart H—Gasoline Sulfur

General Information

§ 80.180 [Reserved]

§ 80.185 [Reserved]

§ 80.190 Who must register with EPA under the sulfur program?

(a) Refiners and importers who are registered by EPA under § 80.76 are deemed to be registered for purposes of this subpart.

(b) Refiners and importers subject to the standards in § 80.195 who are not registered by EPA under § 80.76 must provide to EPA the information required by § 80.76 by November 1, 2003, or not
later than three months in advance of the first date that such person produces or imports gasoline, whichever is later.

(c) Refiners with any refinery subject
to the small refiner standards under § 80.240, or refiners subject to the geographic phase-in area (GPA) standards under § 80.216, who are not registered by EPA under § 80.76 must provide to EPA the information required under § 80.76 by December 31, 2000.

(d) Any refiner who plans to generate credits or allotments under § 80.305 or § 80.275 in any year prior to 2004 who is not registered by EPA under § 80.76 must register under § 80.76 no later than September 30 of the year prior to the first year of credit generation. Any refiner who plans to generate credits in 2000 who is not registered by EPA under § 80.76 must register under § 80.76 no later than May 10, 2000.


### 6824 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

Gasoline Sulfur Standards

§ 80.195 What are the gasoline sulfur standards for refiners and importers?

(a)(1) The gasoline produced by small refiners subject to the standards at § 80.240, and gasoline designated as GPA gasoline under § 80.219(a), are as

follows:

Gasoline sulfur standards for the averaging period beginning:

January 1,
2004 January 1,
2005 January 1, 2006 and subsequent

Refinery or Importer Average ...................................................................................................

... (1) 30.00 30.00 Corporate Pool Average ......................................................................................................... ..... 120.00 90.00 (1) Per-Gallon Cap ................................................................................................................. ........... 300 300 80

1 Not applicable.

(2) The sulfur standards and all compliance calculations for sulfur under this subpart are in parts per million (ppm) and volumes are in gallons.

(3) The averaging period is January 1 through December 31 of each year.

(4) The standards under this paragraph (a) for all imported gasoline shall be met by the importer.

(b)(1) The refinery or importer annual average gasoline sulfur standard is the maximum average sulfur level allowed for gasoline produced at a refinery or imported by an importer during each calendar year starting January 1, 2005.

(2) The annual average sulfur level is calculated in accordance with § 80.205.

(3) The refinery or importer annual average gasoline sulfur standard may be met using credits as provided under § 80.275 or § 80.315.

(4) In 2005 only, the refinery or importer annual average sulfur standard may be met using credits or allotments as provided under § 80.275 or credits as provided under § 80.315.

(c)(1) The corporate pool average gasoline sulfur standards applicable in
2004 and 2005 are the maximum average sulfur levels allowed for a refiner’s or importer’s gasoline production from all of the refiner’s refineries or all gasoline imported by an importer in a calendar year. The corporate pool average standards for a party that is both a refiner and an importer are the maximum average sulfur levels allowed for all the party’s combined gasoline production from all refineries and imported gasoline in a calendar year.

(2) The corporate pool average is
calculated in accordance with the provisions of § 80.205.

(3) The corporate pool average standard may be met using sulfur allotments under § 80.275.

(4) The corporate pool average standards do not apply to approved small refiners subject to the small refiner gasoline sulfur standards under § 80.240.

(5)(i) Joint ventures, in which two or more parties collectively own and operate one or more refineries, will be treated as a separate refiner under this

section.

(ii) One partner to a joint venture may include one or more joint venture refineries in its corporate pool for purposes of complying with the corporate pool average standards. The joint venture will be in compliance for such joint venture refinery(ies) if the partner’s corporate pool average meets the corporate pool average standards. The joint venture entity must demonstrate compliance with the corporate pool average standards for any refinery(ies) owned by the joint venture that are not included in one partner’s corporate pool.

(d)(1) The per-gallon cap standard is
the maximum sulfur level allowed for each batch of gasoline produced or imported starting January 1, 2004.

(2) In 2004 only, a refiner or importer may produce or import gasoline with a per-gallon sulfur content greater than 300 ppm, to a maximum of 350 ppm, provided the following conditions are

met:

(i) The refinery or importer becomes subject to an adjusted per-gallon cap standard in 2005, calculated using the following formula:

ACS=300

¥ (S

max ¥ 300)

Where: ACS=Adjusted cap standard.
S

max=Maximum sulfur content of any gasoline produced at a refinery or imported by an importer during

2004. (ii) The adjusted cap standard calculated under paragraph (d)(2)(i) of this section applies to all gasoline produced at a refinery or imported by an importer during 2005. (iii) The refinery or importer remains subject to the 30.00 average standard under paragraph (a) of this section for

2005.

(iv) The provisions of this paragraph (d)(2) apply to gasoline designated as GPA gasoline under § 80.219(a).

(v) The provisions of this paragraph (d)(2) do not apply to small refiners as defined in § 80.225.

§ 80.200 What gasoline is subject to the sulfur standards and requirements?

For the purpose of this subpart, all reformulated and conventional gasoline and RBOB, collectively called ‘‘gasoline’’ unless otherwise specified, is subject to the standards and requirements under this subpart, with the following exceptions:

(a) Gasoline that is used to fuel aircraft, racing vehicles or racing boats that are used only in sanctioned racing events, provided that:

(1) Product transfer documents associated with such gasoline, and any pump stand from which such gasoline is dispensed, identify the gasoline either as gasoline that is restricted for use in aircraft, or as gasoline that is restricted for use in racing motor vehicles or racing boats that are used only in sanctioned racing events;

(2) The gasoline is completely segregated from all other gasoline throughout production, distribution and sale to the ultimate consumer; and

(3) The gasoline is not made available for use as motor vehicle gasoline, or dispensed for use in motor vehicles, except for motor vehicles used only in sanctioned racing events.

(b) California gasoline as defined in § 80.375.

(c) Gasoline that is exported for sale
outside the U.S.


### 6825 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

§ 80.205 How is the annual refinery or importer average and corporate pool average sulfur level determined?

(a) The annual refinery or importer average and corporate pool average gasoline sulfur level is calculated as
follows:



### S V S

V a i i

i n

i

i n 

### = ×

=

= 

# ∑

∑ ( )

1

1 Where:

S

a=The refinery or importer annual average sulfur value, or corporate pool average sulfur value, as applicable.

Vi=The volume of gasoline produced or imported in batch i.

S i=The sulfur content of batch i determined under § 80.330. n=The number of batches of gasoline produced or imported during the averaging period. i=Individual batch of gasoline produced or imported during the averaging period. (b) All annual refinery or importer average or corporate pool average
calculations shall be conducted to two decimal places.

(c) A refiner or importer may include oxygenate added downstream from the refinery or import facility when calculating the sulfur content, provided the following requirements are met:

(1) For oxygenate added to conventional gasoline, the refiner or importer must comply with the requirements of § 80.101(d)(4)(ii).

(2) For oxygenate added to RBOB, the refiner or importer must comply with the requirements of § 80.69(a).

(d) Refiners and importers must exclude from compliance calculations all of the following:

(1) Gasoline that was not produced at the refinery;

(2) In the case of an importer, gasolinethat was imported as Certified SulfurFRGAS;

(3) Blending stocks transferred to others;

(4) Gasoline that has been included in the compliance calculations for another refinery or importer; and

(5) Gasoline exempted from standards under § 80.200.

(e)(1) A refiner or importer may exceed the refinery or importer annual average sulfur standard specified in § 80.195 for a given averaging period for any calendar year through 2010, creating a compliance deficit, provided that in the calendar year following the year the standard is not met, the refinery or importer shall: (i) Achieve compliance with the refinery or importer annual average sulfur standard specified in § 80.195;
and

(ii) Use additional sulfur credits sufficient to offset the compliance deficit of the previous year.

(2) No refiner or importer may have a compliance deficit in any year after 2010. Any deficit that exists in 2010 must be made up in 2011.

(f) For refiners subject to the corporate pool average who produce some GPA gasoline, the refinery average sulfur value for its GPA gasoline shall be the average sulfur value after applying
credits.

§ 80.210 What sulfur standards apply to gasoline downstream from refineries and importers?

The sulfur standard for gasoline at any point in the gasoline distribution system downstream from refineries and import facilities, including gasoline at facilities of distributors, carriers, oxygenate blenders, retailers and wholesale purchaser-consumers (‘‘downstream location’’), shall be
determined in accordance with the provisions of this section.

(a) Definition. S–RGAS means gasoline that is subject to the standards under § 80.240 or § 80.270, including
Certified Sulfur-FRGAS as defined in § 80.410, except that no batch of gasoline may be classified as S–RGAS if
the actual sulfur content is less than the applicable per-gallon refinery cap standard specified in § 80.195.

(b) Standards for gasoline that does not qualify for S–RGAS downstream
standards. The following standards apply to any gasoline that does not qualify for S–RGAS downstream standards under in paragraph (d) of this

section:

(1) Starting February 1, 2004 the sulfur content of gasoline at any
downstream location other than at aretail outlet or wholesale purchaserconsumer facility, and starting March 1, 2004 the sulfur content of gasoline at any downstream location, shall not exceed 378 ppm.

(2) Except as provided in § 80.220(a), starting February 1, 2005 the sulfur content of gasoline at any downstream
location other than at a retail outlet or wholesale purchaser-consumer facility, and starting March 1, 2005 the sulfur content of gasoline at any downstream location, shall not exceed 326 ppm.

(3) Except as provided in § 80.220(a), starting February 1, 2006 the sulfur content of gasoline at any downstream
location other than at a retail outlet or wholesale purchaser-consumer facility, and starting March 1, 2006 the sulfur content of gasoline at any downstream location, shall not exceed 95 ppm.

(c) Standards for gasoline that qualifies for S–RGAS downstream
standards. In the case of any gasoline that qualifies for S–RGAS downstream standards under paragraph (d) of this section, the sulfur standard shall be the downstream standard for the gasoline calculated under paragraph (f) of this
section. In the case of mixtures of gasoline that qualify for different S– RGAS downstream standards, the sulfur standard shall be the highest downstream standard applicable to any
of the S–RGAS in the mixture.

(d) Gasoline that qualifies for S–RGAS
downstream standards. Gasoline qualifies for S–RGAS downstream standards if all of the following
conditions are met:

(1) The gasoline must be comprised in whole or part of S–RGAS.

(2) Product transfer documents applicable to the gasoline when received at that location must represent that the gasoline contains S–RGAS.

(3) Except as provided in paragraph (d)(4) of this section, the gasoline must have been sampled and tested at that location subsequent to the most recent receipt of gasoline at that location, and
the test result must show a sulfur content greater than:

(i) 350 ppm starting February 1, 2004; (ii) 300 ppm starting February 1, 2005;
and

(iii) 80 ppm (or in the GPA, 300 ppm) starting February 1, 2006.

(4) This sampling and testing condition does not apply for gasoline atany retail outlet, wholesale purchaserconsumer facility, or contained in any transport truck.

(e) Product transfer document information for S–RGAS. (1) On each occasion when any refiner or importer of S–RGAS transfers custody or title to such gasoline, the refiner or importer shall provide to the transferee documents that include the following
information:

(i) Identification of the gasoline as being S–RGAS; and

(ii) The downstream standard applicable to the batch of gasoline under paragraph (f) of this section.

(2) Where gasoline in whole or part is classified as S–RGAS when received by the transferor, and where the gasoline
transferred meets the conditions under paragraph (d) of this section, the transferor shall provide to the transferee, on each occasion when custody or title to gasoline is transferred, documents that include the following information:

(i) Identification of the gasoline as S– RGAS; and


### 6826 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(ii) The applicable downstream standard under paragraph (c) of this section. This does not apply when gasoline is sold or dispensed for use in
motor vehicles at a retail outlet or wholesale purchaser-consumer facility.

(3) No person shall classify gasoline as being S–RGAS except as provided in paragraphs (e)(1) and (e)(2) of this

section.

(4) Product codes may be used to convey the information required by paragraphs (e)(1) and (e)(2) of this section if such codes are clearly understood by each transferee.

(f) Downstream standards applicable to S–RGAS when produced or imported. (1) The downstream standard applicable to any gasoline classified as S–RGAS when produced or imported shall be calculated using the following equation:

D=S+105 ×((S+2)/10 4) 0.4

Where:

D=Downstream sulfur standard.

S=The sulfur content of the refiner’s batch determined under § 80.330.

(2) Where more than one S–RGAS batch is combined, prior to shipment, at the refinery or import facility where the S–RGAS is produced or imported, the downstream standard applicable to the mixture shall be the highest downstream standard, calculated under paragraph (f)(1) of this section, for any
S–RGAS contained in the mixture.

§ 80.211 [Reserved]

§ 80.212 What requirements apply to oxygenate blenders?

Effective January 1, 2004, oxygenate blenders who blend oxygenate into gasoline downstream of the refinery that produced the gasoline or the import facility where the gasoline was imported, are not subject to the requirements of this subpart applicable to refiners for this gasoline, but are subject to the requirements and prohibitions applicable to downstream parties and the prohibition specified in § 80.385(e).

§§ 80.213–80.214 [Reserved]

Geographic Phase-In Program

§ 80.215 What is the scope of the geographic phase-in program?

(a) Geographic phase-in area. (1) The following states comprise the geographic phase-in area (GPA) subject to the provisions of the geographic phase-in program: North Dakota, Montana, Idaho, Wyoming, Utah, Colorado, New Mexico, and Alaska.

(2) Additional counties or tribal lands in states adjacent to the states identified in paragraph (a) of this section will be included in the GPA if any of the following criteria is met:

(i) Approximately 50% or more of the total volume of gasoline in the county or tribal land in 1999, as measured at the terminal(s) and bulk station(s) in the county or tribal land, was received from a refinery or refineries located in the area specified in paragraph (a)(1) of this section; or

(ii) Approximately 50% or more of the total volume of gasoline dispensed in the county or tribal land in 1999 was received from a refinery or refineries located in the area specified in paragraph (a)(1) of this section; or

(iii) Approximately 50% or more of the total commercial and private dispensing outlets in the county or tribal land in 1999 were supplied by gasoline produced by a refinery or refineries located in the area specified in paragraph (a)(1) of this section.

(3) The criteria of paragraphs (a)(2)(i), (ii) and (iii) of this section are without regard to the method of gasoline delivery (e.g, pipeline, truck, rail or barge). The criteria of paragraphs (a)(2)(ii) and (a)(2)(iii) of this section are without regard to whether the gasoline was transported directly from the refinery to the dispensing outlet or distributed through a terminal or bulk

station.

(b) Duration of the program. The geographic phase-in program applies to the 2004, 2005, and 2006 annual averaging periods.

(c) Persons eligible. Any refiner or importer who produces or imports gasoline for use in the geographic area under paragraph (a) of this section is eligible to apply for the geographic phase-in program. The provisions of the geographic phase-in program shall apply to imported gasoline through the importer.

§ 80.216 What standards apply to gasoline produced or imported for use in the GPA?

(a)(1) The refinery or importer annual average sulfur standard for gasoline produced or imported for use in the geographic area under § 80.215 shall be
the lesser of:

(i) 150 ppm; or (ii) The refinery’s or importer’s 1997/ 1998 average sulfur level, calculated in accordance with § 80.295, plus 30 ppm.

(2) In the case of any refinery whose actual annual sulfur average decreases to a level lower than the refinery’s annual average sulfur standard established under paragraph (a)(1) of this section during the period 2000 through 2003, the standard applicable to that refinery from 2004 through 2006 shall be the lowest average sulfur content for any year in which the refinery generated allotments or credits under § 80.275(a) or § 80.305 plus 30 ppm, not to exceed 150 ppm.

(b) The per-gallon cap standard for gasoline produced or imported for use in the GPA under paragraph (a) of this section shall be 300 ppm, except as specified in § 80.195(d).

(c) The refinery or importer annual average sulfur level is calculated in accordance with the provisions of § 80.205.

(d) The refinery or importer annual average standard under paragraph (a) of this section may be met using sulfur allotments or credits as provided under §§ 80.275 and 80.315.

(e) Gasoline produced by approved small refiners subject to the standards under § 80.240 is not subject to the standards under paragraphs (a) and (b)
of this section.

(f)(1) A refiner or importer whose gasoline production or volume of imported gasoline in 2004 or 2005 is comprised of ≥ 50% of gasoline designated as GPA gasoline under § 80.219 shall not be required to meet the corporate pool average standards under § 80.195 for its gasoline production or imported gasoline during the applicable averaging period.

(2) A refiner or importer whose gasoline production or volume of imported gasoline in 2004 or 2005 is comprised of less than 50% of gasoline designated as GPA gasoline under § 80.219 must meet the corporate pool average standards under § 80.195 for all the refiner’s gasoline production or the importer’s volume of imported gasoline during the applicable averaging period.

(g) The provisions for compliance deficits under § 80.205(e) do not apply to gasoline subject to the standards under paragraphs (a) and (b) of this

section.

§ 80.217 How does a refiner or importer apply for the GPA standards?

(a) To apply for the GPA standards under § 80.216, a refiner or importer must submit an application in accordance with the provisions of § 80.290.

(b) Applications under paragraph (a) of this section must be submitted by December 31, 2000.

(c)(1) If approved, EPA will notify the refiner or importer of each refinery’s or the importer’s annual average sulfur standard for gasoline produced for use in the GPA for the 2004 through 2006 annual averaging periods.

(2) If disapproved, the refiner or importer must comply with the standards in § 80.195 for gasoline produced for use in the GPA.

(d) If EPA finds that a refiner or importer provided false or inaccurate


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information on its application under this section, upon notice from EPA, the refiner’s or importer’s application will
be void ab initio.

§ 80.218 [Reserved]

§ 80.219 Designation and downstream requirements for GPA gasoline.

The requirements and prohibitions specified in this section apply during the period January 1, 2004 through December 31, 2006.

(a) Designation. Any refiner or importer shall designate any gasoline produced or imported that is subject to the standards under § 80.216 as ‘‘GPA’’ gasoline.

(b) Product transfer documents. (1) On each occasion that any person transfers custody or title to gasoline designated as GPA gasoline, other than when gasoline is sold or dispensed for
use in motor vehicles at a retail outlet or wholesale purchaser-consumer facility, the transferor shall provide to
the transferee documents that include the following information:

(i) Identification of the gasoline as being GPA gasoline;

(ii) A statement that the gasoline may
not be distributed or sold for use outside the geographic phase-in area.

(2) Except for transfers to truck carriers, retailers and wholesale purchaser-consumers, product codes may be used to convey the information required by paragraph (b)(1) of this section if such codes are clearly understood by each transferee.

(3) The requirements under paragraph (b)(1) of this section are in addition to the requirement under § 80.210(e), where appropriate, to identify gasoline as being S–RGAS.

(c) GPA gasoline use prohibitions. (1) All parties in the distribution system, including refiners, importers, distributors, carriers, oxygenate blenders, retailers and wholesale purchaser-consumers, are prohibited
from:

(i) Selling, offering for sale, dispensing, distributing, storing or transporting GPA gasoline for use outside the geographic phase-in area;
and

(ii) Commingling GPA gasoline with gasoline not designated as GPA gasoline
unless the mixture is classified as GPA gasoline.

(2) Gasoline not designated as GPA gasoline may be distributed or sold for use in the geographic phase-in area.

§ 80.220 What are the downstream standards for GPA gasoline?

(a) GPA gasoline. (1) During the period February 1, 2004 through January 31, 2005, the sulfur content of GPA gasoline at any downstream location
other than at a retail outlet or wholesale purchaser-consumer facility, and during the period March 1, 2004 through February 28, 2005, the sulfur content of GPA gasoline at any downstream location shall not exceed 378 ppm.

(2) During the period February 1, 2005 through January 31, 2007, the sulfur content of GPA gasoline at any
downstream location other than at aretail outlet or wholesale purchaserconsumer facility, and during the period March 1, 2005 through February 28, 2007, the sulfur content of GPA gasoline at any downstream location shall not exceed 326 ppm.

(b) GPA gasoline mixed with S–RGAS. Notwithstanding the requirements in paragraph (a) of this section, the sulfur standard applicable to a mixture of GPA gasoline and S–RGAS gasoline at a downstream location shall be the greater of the standard under paragraph (a) of
this section or the standard determined under § 80.210.

Hardship Provisions

§ 80.225 What is the definition of a small

refiner?

(a) A small refiner is defined as any person, as defined by 42 U.S.C. 7602(e), who: (1)(i) Produces gasoline at a refinery by processing crude oil through refinery processing units;

(ii) Employed an average of no more than 1,500 people, based on the average number of employees for all pay periods from January 1, 1998, to January 1, 1999;
and

(iii) Had an average crude capacity less than or equal to 155,000 barrels per calendar day (bpcd) for 1998.

(2) For the purpose of determining the number of employees and crude capacity under paragraph (a)(1) of this section, the refiner shall include the employees and crude capacity of any subsidiary companies, any parent company and subsidiaries of the parent company, and any joint venture partners.

(b) The definition under paragraph (a) of this section applies to domestic and foreign refiners. For any refiner owned by a governmental entity, the number of employees as specified in paragraph (a)
of this section shall include all employees of the governmental entity.

(c) If, without merger with, or acquisition of, another business unit, a company with approved small refiner status under § 80.235 exceeds 1,500 employees, or a corporate crude capacity of 155,000 bpcd after January 1, 1999, it will be considered a small
refiner for the duration of the small refiner program. (d) Notwithstanding the definition in paragraph (a) of this section, refiners who acquire a refinery after January 1, 1999, or reactivate a refinery that was shutdown or was non-operational between January 1, 1998, and January 1, 1999, may apply for small refiner status in accordance with the provisions of § 80.235.

§ 80.230 Who is not eligible for the hardship provisions for small refiners?

(a) The following are not eligible for the hardship provisions for small
refiners:

(1) Refiners of refineries built after January 1, 1999;

(2) Refiners who exceed the employee or crude oil capacity criteria under § 80.225(a) on January 1, 1999, but who meet these criteria after that date, regardless of whether the reduction in employees or crude capacity is due to operational changes at the refinery or a company sale or reorganization;

(3) Importers; and (4) Refiners who produce gasoline other than by processing crude oil through refinery processing units.

(b)(1) Refiners who qualify as small under § 80.225, and subsequently employ more than 1,500 people as a result of merger with or acquisition of or by another entity, are disqualified as
small refiners. If this occurs the refiner shall notify EPA in writing no later than 20 days following this disqualifying

event.

(2) Any refiner who qualifies as small under § 80.225 may elect to meet the standards under § 80.195 by notifying EPA in writing no later than November 15 prior to the year the change will

occur.

(3) Any refiner whose status changes under paragraph (b)(1) or (2) of this
section shall meet the standards under § 80.195 beginning with the first averaging period subsequent to the status change.

§ 80.235 How does a refiner obtain approval as a small refiner?

(a) Applications for small refiner status must be submitted to EPA by December 31, 2000, except for applications submitted pursuant to § 80.225(d), which must be submitted by June 1, 2002.

(b) Applications for small refiner status must be sent to: U.S. EPA, Attn: Sulfur Program (6406J), 401 M Street, SW, Washington, DC 20460. For commercial delivery: U.S. EPA, Attn: Sulfur Program (6406J), 501 3rd Street, NW, Washington, DC 20001.

(c) The small refiner status application must contain the following information for the company seeking


### 6828 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

small refiner status, plus any subsidiary companies, any parent company and subsidiaries of the parent company, and any joint venture partners:

(1)(i) A listing of the name and address of each location where any employee worked during the 12 months preceding January 1, 1999; the average number of employees at each location based upon the number of employees for each pay period for the 12 months preceding January 1, 1999; and the type
of business activities carried out at each location; or

(ii) In the case of a refiner who acquires a refinery after January 1, 1999, or reactivates a refinery that was shutdown between January 1, 1998, and January 1, 1999, a listing of the name and address of each location where any employee of the refiner worked since the refiner acquired or reactivated the refinery; the average number of employees at any such acquired or reactivated refinery during each calendar year since the refiner acquired or reactivated the refinery; and the type
of business activities carried out at each
location.

(2) The total corporate crude capacity of each refinery as reported to the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE). The information submitted to EIA is presumed to be correct. In cases where a company disagrees with this information, the company may petition EPA with appropriate data to correct the record within 60 days after the company submits its application for small refiner

status.

(3) A letter signed by the president, chief operating or chief executive officer of the company, or his/her designee, stating that the information contained in the application is true to the best of his/ her knowledge.

(4) Name, address, phone number, facsimile number and E-mail address (if available) of a corporate contact person.

(d) For joint ventures, the total number of employees includes the combined employee count of all corporate entities in the venture.

(e) For government-owned refiners, the total employee count includes all government employees.

(f) Approval of small refiner status for refiners who apply under § 80.225(d)
will be based on all information submitted under paragraph (c) of this section. Where appropriate, the employee and crude oil capacity criteria
for such refiners will be based on the most recent 12 months of operation.

(g) EPA will notify a refiner of approval or disapproval of small refiner status by letter.

(1) If approved, EPA will notify the refiner of each refinery’s applicablebaseline standard and volume, and pergallon cap under § 80.240.

(2) If disapproved, the refiner must comply with the standards in § 80.195.

(h) If EPA finds that a refiner provided false or inaccurate information on its application for small refiner status, upon notice from EPA the
refiner’s small refiner status will be void
ab initio.

(i) Upon notification to EPA, an approved small refiner may withdraw
its status as a small refiner. Effective on January 1 of the year following such notification, the small refiner will become subject to the standards at § 80.195.

§ 80.240 What are the small refiner gasoline sulfur standards?

(a) The gasoline sulfur standards for an approved small refiner are as follows:

Refinery baseline sulfur level Temporary sulfur standards for small refiners applicable from January 1, 2004 through December 31, 2007

Annual average Per gallon cap

0 to 30 ........................................................................................................................ ............................. 30.00 300

31 to 200 ...................................................................................................................... ........................... Baseline level 300

201 to 400 ..................................................................................................................... .......................... 200.00 300

401 to 600 ..................................................................................................................... .......................... 50% of baseline Factor of 1.5 times the average

standard.

601 and above .................................................................................................................. ...................... 300.00 450

(b) The refinery annual average sulfur
standards must be met on an annual calendar year basis for each refinery owned by a small refiner. The refinery annual average sulfur level is calculated in accordance with the provisions of § 80.205.

(c)(1) The refinery annual average standards specified in paragraph (a) of this section apply to the volume of gasoline produced by a small refiner’s refinery up to the lesser of:

(i) 105% of the baseline gasoline
volume as determined under § 80.250(a)(1); or

(ii) The volume of gasoline produced at that refinery during the averaging period by processing crude oil.

(2) If a refiner exceeds the volume limitation in paragraph (c)(1) of this section during any averaging period, the annual average sulfur standard applicable to the refiner for that averaging period is calculated as
follows:



### S V S AF V V

V sr bb ab

a 

### = ×+ ×−

( ) ( ( ))

Where:

S

sr=Small refiner annual average sulfur
standard.

Vb=Applicable volume under paragraph (c)(1) of this section.

V

a=Averaging period gasoline volume.

S b=Small refiner sulfur baseline as determined under § 80.250. AF=Adjustment factor (120 in 2004; 90 in 2005; and 30 in 2006 and thereafter).
(3) The small refiner average standards under paragraph (a) of this section may be met using sulfur allotments or credits as provided under § 80.275 or § 80.315. (4) The provisions for compliance deficits under § 80.205(e) do not apply to small refiners subject to the standards
under this section.

(d) In the case of any refiner with small refiner status who generates sulfur allotments or credits pursuant to § 80.275(a) or § 80.305, the baseline applicable to that refiner’s refinery for purposes of establishing the standard for the refinery under paragraph (a) of this section beginning in 2004 shall be the lowest annual average sulfur content for any year during the period in which the refiner generated allotments or credits.

§ 80.245 How does a small refiner apply

for a sulfur baseline?

(a) Any refiner seeking small refiner status must apply for a refinery sulfur baseline by the deadline under § 80.235 for each of the refiner’s refineries by providing the following information:


### 6829 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(1) A sulfur baseline and baseline volume for every refinery calculated in accordance with § 80.250.

(2) The following information for each batch of gasoline produced in 1997–

1998:

(i) Batch number assigned to the batch under § 80.65(d) or § 80.101(i);

(ii) Volume; and (iii) Sulfur content. (3) For any refiner who acquires a refinery after January 1, 1999, or reactivates a refinery that was shut down or non-operational between January 1, 1998, and January 1, 1999, the average sulfur level and average volume of gasoline produced during each year the refinery was in operation after the refinery was acquired or reactivated. Where appropriate, the
baseline sulfur level and volume for
such refineries will be determined based on the annual average for the most recent year of operation.

(b) The sulfur baseline application
must be submitted to the address specified in § 80.235(b).

§ 80.250 How is the small refiner sulfur

baseline and volume determined?

(a)(1) The small refiner baseline volume is determined for each refinery
as follows:



### V V

b i

i n



### = =



# ∑ ( )

1


### 2

Where:

VB =Baseline volume.

VI=Volume of gasoline batch i. n=Total number of batches of gasoline produced from January 1, 1997, through December 31, 1998. i=Individual batch of gasoline produced from January 1, 1997, through December 31, 1998.
(2) The small refiner sulfur baseline is determined for each refinery as follows:



### S V S

V b i i

i n

i

i n 

### = ×

=

= 

# ∑

∑ ( )

1

1

Where:
S b=Small refiner sulfur baseline.

Vi=Volume of gasoline batch i.
S i=Sulfur content of batch i. n=Total number of batches of gasoline produced from January 1, 1997, through December 31, 1998. i=Individual batch of gasoline produced from January 1, 1997, through December 31, 1998. (b) Foreign refiners who do not have an approved refinery baseline under § 80.94 must follow the procedures specified in § 80.410(b).

(c) If at any time a small refinery baseline is determined to be incorrect, the corrected baseline applies ab initio and the annual average standards and cap standards are deemed to be those applicable under the corrected
information.

§ 80.255 Compliance plans and demonstration of commitment to produce low sulfur gasoline.

The requirements of this section apply to any refiner approved for small
refiner standards who wishes to be eligible for a hardship extension under § 80.260.

(a) Compliance commitment. By no later than June 1, 2004, any refiner who is approved for small refinery standards must submit a preliminary report to
EPA which outlines the refiner’s timeline for compliance and a project plan which discusses permits, capital commitments and engineering plans for making the necessary modifications to produce gasoline that meets the 30 ppm refinery average and 80 ppm per-gallon cap sulfur standards under § 80.195 on or before January 1, 2008. Documents showing activities and progress in these areas should be provided, if available.

(b) Demonstration of Progress. (1)(i) By no later than June 1, 2005, the small refiner must submit a report to EPA that states in detail the progress toward compliance with the 30 ppm refinery average and 80 ppm cap sulfur
standards to date based on their timeline and project plan. The report
must include:

(A) Copies of approved permits for construction of the equipment, or the permit application if approval is still pending;

(B) Copies of contracts for design and construction; and

(C) Any available evidence of having secured the necessary financing to complete the required construction;

(ii) If the refiner anticipates any difficulties in meeting its compliance commitments under this section, the refiner must submit a detailed report of
all efforts made to date and the factors that may cause delay, including costs, specification of engineering or other design work needed and reasons for delay, specification of equipment needed and any reasons for delay, potential equipment suppliers and history of negotiations, and any other relevant information. If unavailability of equipment is a factor, the report must include a discussion of other options
considered and the reasons these other options are not feasible. (2) By no later than June 1, 2006, the
small refiner must submit to EPA
evidence that on-site construction has begun and that, absent unforeseen difficulties, the small refiner will be producing complying gasoline by January 1, 2008. If construction has not begun, the refiner must demonstrate that
it has made all reasonable efforts to begin construction, that substantial progress is being made to begin construction as soon as possible, and that construction can be completed in time to begin production of gasoline that complies with the standards of § 80.195 by January 1, 2008.

(c) Additional information. The Administrator may request any additional information necessary to
determine a refiner’s commitment and/ or progress toward meeting the standards in § 80.195 by 2008.

(d) Failure to comply with requirements. Any small refiner who fails to submit the progress reports required under this section will not be eligible for a hardship extension under § 80.260.

§ 80.260 What are the procedures and requirements for obtaining a hardship

extension?

(a) An approved small refiner who has filed the reports specified in § 80.255 may apply to EPA for a hardship
extension of the small refiner standards for calendar years 2008 and 2009. The application must be submitted in writing no later than January 1, 2007, to U.S. EPA, Attn: Sulfur Program (6406J), 401 M Street, SW, Washington, DC 20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur Program, 501 3rd Street NW, Washington, DC 20001.

(b) The application must specify the factors that demonstrate a significant economic hardship and must provide a detailed discussion regarding the inability of the refinery to produce gasoline meeting the requirements of § 80.195. Such an application must include, at a minimum, the following
information:

(1) Documentation of efforts made to obtain necessary financing, including:

(i) Copies of loan applications for the necessary financing of the construction of appropriate sulfur reduction technology and other equipment procurements or improvements; and

(ii) If financing has been disapproved or is otherwise unsuccessful, documents supporting the basis for that disapproval and evidence of efforts to pursue other means of financing;

(2) A detailed analysis of the reasons the refinery is unable to produce gasoline meeting the standards of


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§ 80.195 in 2008, including costs, specification of equipment still needed, potential equipment suppliers, and efforts already completed to obtain the necessary equipment;

(3) If unavailability of equipment is part of the reason for the inability to comply, a discussion of other options considered, and the reasons these other options are not feasible;

(4) If relevant, a demonstration that a needed or lower cost technology is immediately unavailable, but will be available in the near future, and full information regarding when and from what sources it will be available;

(5) Schematic drawings of the refinery configuration as of January 1, 1999, and as of the date of the hardship extension application, and any planned future additions or changes;

(6) If relevant, a demonstration that a temporary unavailability exists of engineering or construction resources necessary for design or installation of the needed equipment;

(7) If sources of crude oil lower in sulfur than what the refiner is currently using are available, full information regarding the availability of these different crude sources, the sulfur content of those crude sources, the cost
of the different crude sources over the past five years, and an estimate of gasoline sulfur levels achievable by the refinery if the lower sulfur crude sources were used;

(8) A discussion of any sulfur
reductions that can be achieved from current levels;

(9) The date the refiner anticipates compliance with the standards in § 80.195 can be achieved at its refinery;

(10) An analysis of the economic impact of compliance on the refiner’s business (including financial statements from the last 5 years, or for any time period up to 10 years, at EPA’s request);
and

(11) Any other information regarding other strategies considered, including strategies or components of strategies
that do not involve installation of equipment, and why meeting the standards in § 80.195 beginning in 2008
is infeasible.

(c) The hardship extension application must contain a letter signed by the president or the chief operating
or chief executive officer of the company, or his/her designee, stating
that the information contained in the application is true to the best of his/her knowledge.

§ 80.265 How will the EPA approve or disapprove a hardship extension application?

(a) EPA will evaluate each application for hardship extension on a case-by-case basis. The factors considered for a hardship extension may include: The refiner’s financial position and efforts to obtain capital funding; the refiner’s efforts to procure necessary equipment, obtain design and engineering services and construction contractors; the availability of desulfurization equipment; and any other relevant factor. An extension will be granted for a refinery for the 2008 averaging period
if the small refiner who owns the refinery adequately demonstrates that severe economic hardship would result if compliance with the standards in § 80.195 is required in 2008, or that compliance with the standard in 2008 is not feasible for reasons beyond the refiner’s control, and that the refiner has made the best efforts possible to achieve compliance with the national standards by January 1, 2008. Upon reapplication by the refiner, if EPA determines that further relief is appropriate, EPA may grant a further extension through the 2009 averaging period. In no case will
a further extension for the 2009 averaging period be granted unless the refiner demonstrates conclusively that it has financing in place and that it will be able to complete construction and meet the national gasoline sulfur standards no later than December 31,

2009.

(b) EPA may request more information, if necessary, for evaluation of the application. If requested
information is not submitted within the time specified in EPA’s request, or any extensions granted, the application may
be denied.

(c) EPA will notify the refiner of approval or disapproval of hardship extension by letter.

(1) If approved, EPA will also notify
the refiner of the date that full compliance with the standards specified at § 80.195 must be achieved or what interim sulfur levels or schedules apply, if any.

(2) If disapproved, beginning January 1, 2008, the refinery is subject to the requirements in § 80.195. Refiners who
receive an extension for the 2008 averaging period shall meet the standards in § 80.195 beginning on January 1, 2009, unless EPA grants an extension of the hardship relief for an additional year. If such an additional extension is granted, the refiner shall meet the standards in § 80.195 on January 1, 2010.

(d) Refiners who receive a hardship extension may be required to meet more stringent standards than those which apply to them during 2007, and/or could be required to offset excess sulfur levels. EPA may impose reasonable conditions on an extension, such as requiring segregation of the small refiner’s gasoline or requiring the gasoline to be sold for use in older vehicles only.

§ 80.270 Can a refiner seek temporary relief from the requirements of this subpart?

(a) EPA may permit a refiner to produce and distribute gasoline which does not meet the requirements of this subpart if the refiner demonstrates that:

(1) Unusual circumstances exist that impose extreme hardship and significantly affect ability to comply by the applicable date; and

(2) It has made best efforts to comply with the requirements of this subpart (including making efforts to obtain credits and/or allotments).

(b) Applications must be submitted to EPA by September 1, 2000. Relief may be granted from some or all of the requirements of this subpart, at EPA’s discretion; however, EPA reserves the right to deny applications for appropriate reasons, including unacceptable environmental impact. Approval to distribute gasoline which does not meet the requirements of this subpart may be granted for such time period as EPA determines is appropriate, but shall not extend beyond January 1, 2008.

(c)(1) Applications must include a plan demonstrating how the refiner will comply with the requirements of this subpart as expeditiously as possible. The plan shall include a showing that contracts are or will be in place for engineering and construction of desulfurization equipment, a plan for applying for and obtaining any permits necessary for construction, a description of plans to obtain necessary capital, and
a detailed estimate of when the requirements of this subpart will be met.

(2) Applications must include a detailed description of the refinery configuration and operations, including, at a minimum, the following
information:

(i) The portion of gasoline production that is produced using an FCC unit;

(ii) The refinery’s hydrotreating capacity;

(iii) The refinery’s total reformer unit throughput capacity;

(iv) The refinery’s total crude capacity;

(v) Total crude capacity of any other refineries owned by the same entity;

(vi) Total volume of gasoline production at the refinery;

(vii) Total volume of other refinery products; and

(viii) Geographic location(s) in which gasoline will be sold.

(3) Applications must include, at a minimum, the following information:


### 6831 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(i) Detailed description of efforts to obtain capital for refinery investments;

(ii) Bond rating of entity that owns the refinery; and

(iii) Estimated capital investment needed to comply with the requirements of this subpart by the applicable date.

(4) Applicants must also provide any other relevant information requested by

EPA.

(d) EPA may impose any reasonable conditions on waivers granted under
this section.

Allotment Trading Program

§ 80.275 How are allotments generated

and used?

(a) Generation of allotments and
credits in 2003. (1) During 2003 only, any domestic or foreign refiner may have the option to generate credits in accordance with the provisions of § 80.305 or generate allotments and credits under paragraph (a)(2) of this

section.

(2) If the average sulfur content of the gasoline produced at a refinery is less than the refinery’s baseline as determined under § 80.295 and is 60 ppm or less, allotments and credits may be generated using the following procedures. This paragraph (a) does not apply to importers.

(i) If the average sulfur content of the gasoline produced at a refinery is less than or equal to 30, and the refinery’s sulfur baseline is greater than 120, the following procedures apply:

SATypeB = (30 ¥ Sa

a) × V
SATypeA = (V × 90) × 0.8 CR = (S Base ¥ 120) × V

(ii) If the average sulfur content of the gasoline produced at a refinery is less than or equal to 30, and the refinery’s sulfur baseline is greater than 30 but less than or equal to 120, the following procedures apply:

SATypeB = (30 ¥ S

a) × V
SATypeA = ((S Base ¥ 30) × V) × 0.8

(iii) If the average sulfur content of the gasoline produced at a refinery is less than or equal to 30, and the refinery’s sulfur baseline is less than or equal to 30, the following procedures apply:

SATypeB = ( S Base ¥ S

a) × V

(iv) If the average sulfur content of the gasoline produced at a refinery is greater than 30, and the refinery’s sulfur baseline is greater than 120, the following procedures apply:

SATypeA = ((120 ¥ S

a) × V) × 0.8 CR = (S Base ¥ 120) × V

(v) If the average sulfur content of the gasoline produced at a refinery is greater than 30, and the refinery’s sulfur baseline is less than or equal to 120, the following procedures apply: SATypeA = ((S Base ¥ Sa) × V) × 0.8 (vi) For purposes of the equations under paragraphs (a)(2)(i) through (v) of this section, the following definitions apply:

SATypeB = Type B sulfur allotments generated.

SATypeA = Type A sulfur allotments generated. CR = Credits generated.

S Base = Refinery’s sulfur baseline value under § 80.295.

S

a = Average sulfur content of the gasoline produced at the refinery during 2003 (or for a foreign refinery, all gasoline produced during 2003 that was imported into the U.S.). V = Volume of gasoline produced at the refinery during 2003 (or for a foreign refinery, all gasoline produced during 2003 that was imported into the U.S.). (b) Generation of allotments in 2004
and 2005. During 2004 and 2005 only, refiners and importers that have corporate pool average sulfur levels below the corporate pool average standards under § 80.195 may generate sulfur allotments separately for each year using the following procedures.

(1) If the average sulfur content of the gasoline produced or imported is less than 30 the following procedures apply:

SATypeB = (30 ¥ S

a) × V

a SATypeA = (S PS ¥ 30) × V

a

(2) If the average sulfur content of the gasoline produced or imported is equal to or greater than 30 the following procedures apply:

SATypeA = (S PS ¥ S

a) × V

a

(3) For purposes of the equations under paragraphs (b)(1) and (2) of this section, the following definitions apply:

SATypeB = Type B sulfur allotments generated.

SATypeA = Type A sulfur allotments generated.

S

a = Corporate pool average sulfur level for the year.

S PS = Corporate pool average standard (120 in 2004; 90 in 2005).

V

a = Total volume of gasoline produced and/or imported during the year.
(c) Use of sulfur allotments to meet
standards. (1) Refiners and importers may use Type A and Type B sulfur allotments to meet the corporate pool average standards under § 80.195, except that if allotments generated in
2003 or 2004 are used to meet the corporate pool standard in 2005 the allotments generated in 2003 or 2004 shall be reduced in value by 50%.

(2) Small refiners subject to the standards under § 80.240, and refiners and importers of gasoline designated as GPA gasoline under § 80.219(a), may
use sulfur allotments to meet their annual average refinery or importer
standards.

(d) Transfers of sulfur allotments. Sulfur allotments generated under this section may be transferred, provided
that:

(1) No allotment may be transferred more than twice: The first transfer by the refiner or importer who generated the allotment may only be made to a refiner or importer who intends to use the allotment; if the transferee cannot use the allotment, it may make the second, and final, transfer only to a refiner or importer who intends to use the allotment. In no case may an
allotment be transferred more than twice before being used or terminated.

(2) The allotment transferor must apply any allotments necessary to meet the transferor’s corporate pool average standard before transferring allotments to any other refiner or importer or before converting allotments into credits.

(3) The transferor must supply to the transferee records indicating the year of generation and type of the allotments, the identity of the refiner or importer who generated the allotments, and the identity of the transferring party, if it is not the same part that generated the
allotments.

(4) The transferor must inform the transferee whether any transferred allotments are Type A allotments or Type B allotments, as defined in paragraphs (a) and (b) of this section.

(5) In the case of allotments that have been calculated or created improperly,
or are otherwise determined to be invalid, the following provisions apply:

(i) Invalid allotments cannot be used to achieve compliance with the transferee’s corporate pool average standard or be converted to credits, regardless of the transferee’s good faith
belief that the allotments were valid.

(ii) The refiner or importer who used the allotments, and any transferor of the allotments, must adjust their allotment records and reports and sulfur calculations as necessary to reflect the proper allotments.

(iii) Any allotments remaining after correcting for the improperly created allotments must first be applied to
correct the invalid transfers before the transferor may transfer any other allotments or before converting
allotments into credits.

(e) Conversion of allotments into
credits. A refiner or importer may convert allotments into credits using the following procedures:

(1) Type A allotments may be
converted into credits with the same requirements and limitations on use that


### 6832 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

apply under § 80.315 to credits generated in 2000 through 2003.

(2) Type B allotments may be
converted into credits with the same requirements and limitations on use that apply under § 80.315 to credits generated in 2004 and later, based on the year of creation of the allotment.

(f) Small refiners. Small refiners subject to the standards under § 80.240 may not generate sulfur allotments under paragraph (b) of this section.

(g) GPA gasoline. GPA gasoline that is included in the refiner’s or importer’s corporate pool average under § 80.216(f)(2) must be included in the calculations under paragraph (b) of this section. No refiner or importer may generate allotments in 2004 or 2005 who is not required to meet the corporate pool average standards.

Averaging, Banking and Trading (ABT) Program—General Information

§ 80.280 [Reserved]

§ 80.285 Who may generate credits under the ABT program?

(a) Credit generation in 2000 through

2003. (1) Credits may be generated in 2000 through 2003 under § 80.305 by refiners who produce gasoline from crude oil, and are:

(i) Refiners who establish a sulfur baseline under § 80.295;

(ii) Foreign refiners with approved baselines under § 80.94, or baselines established in accordance with § 80.410;

or (iii) Small refiners for any refinery subject to the standards under § 80.240, using their small refiner baseline established under § 80.250.

(2) Importers and oxygenate blenders may not generate credits under § 80.305.

(b) Credit generation beginning in

2004. (1) Credits may be generated beginning in 2004 under § 80.310 by:

(i) Refiners and importers subject to the standards under § 80.195;

(ii) Refiners and importers of gasoline designated as GPA gasoline under § 80.219, using the lesser of: 150 ppm; or the refiner’s or importer’s baseline calculated under § 80.295; or the refinery’s lowest annual average sulfur content for any year from 2000 through 2003 during which the refiner generated credits (for any party generating credits under both paragraph (b)(1)(i) of this section and this paragraph (b)(1)(ii),
such credits must be calculated separately); or

(iii) Small refiners for any refinery subject to the standards under § 80.240, using refinery’s standard established under § 80.240.

(2) Generation of credits for all imported gasoline shall be through the importer. (3) Oxygenate blenders may not generate credits under § 80.310.

§ 80.290 How does a refiner apply for a
sulfur baseline?

(a) The refiner must submit an application to EPA which includes the information required under paragraph (c) of this section no later than September 30 of the year in which the refiner plans to begin generating credits, or the refiner or an importer plans to sell gasoline in the geographic phase-in area in accordance with § 80.217.

(b) The sulfur baseline request must be sent to: U.S. EPA, Attn: Sulfur Program (6406J), 401 M Street SW., Washington, DC 20460. For commercial (non-postal) delivery: U.S. EPA, Attn: Sulfur Program, 501 3rd Street NW., Washington, DC 20001.

(c) The sulfur baseline application must include the following information:

(1) A listing of the names and addresses of all refineries owned by the corporation for which the refiner is applying for a sulfur baseline.

(2) The annual average gasoline sulfur baseline for gasoline produced in 1997– 1998, for each refinery for which the refiner is applying for a sulfur baseline, calculated in accordance with § 80.295.

(3) A letter signed by the president, chief operating or chief executive officer, of the company, or his/her delegate, stating that the information
contained in the sulfur baseline
determination is true to the best of his/ her knowledge.

(4) Name, address, phone number,
facsimile number and E-mail address of a corporate contact person.

(5) The following information for each batch of gasoline produced in 1997–

1998:

(i) Batch number assigned to the batch under § 80.65(d) or § 80.101(i);

(ii) Volume; and (iii) Sulfur content. (d) Foreign refiners who do not have an approved refinery baseline under § 80.94 must follow the procedures specified in § 80.410(b).

(e) Within 60 days of receipt of an application under this section, EPA will notify the refiner of approval of the refinery’s baseline or of any deficiencies in the application.

(f) If at any time the baseline
submitted in accordance with the requirements of this section is determined to be incorrect, EPA will notify the refiner of the corrected
baseline.

(g) Any refiner that seeks temporary relief under § 80.270 shall apply for a refinery sulfur baseline in accordance with the provisions of this section and § 80.295, and if applicable, § 80.410(b), no later than September 1, 2000. ABT Program—Baseline Determination

§ 80.295 How is a refinery sulfur baseline

determined?

(a) A refinery’s gasoline sulfur baseline for the purpose of generating credits during years 2000 through 2003 is calculated using the following equation:



### S Vi Si

Vi Base i n

i n 

### = × 

## ( )

=

= 

# ∑

∑

1

1

Where:

S Base=Sulfur baseline value.

Vi=Volume of gasoline batch i.

S i=Sulfur content of gasoline batch i. n=Total number of batches of gasoline produced during January 1, 1997 through December 31, 1998. i=Individual batch of gasoline produced during January 1, 1997 through December 31, 1998. (b) Any refiner who, under § 80.65 or § 80.101(d)(4), included oxygenate blended downstream in compliance
calculations for 1997–1998 must include this oxygenate in the baseline
calculations for sulfur content under paragraph (a) of this section.

§ 80.300 [Reserved]

ABT Program—Credit Generation

§ 80.305 How are credits generated during the time period 2000 through 2003?

(a) Credits must be calculated as
follows:

CR

a=V

a × (S Base ¥ S

a)

Where:

CR

a=Credits generated for the averaging period.

V

a=Total volume of gasoline produced during the averaging period at the refinery.

S Base=Sulfur baseline value for the refinery established under § 80.250 or § 80.295.
S

a=Actual annual average sulfur level for gasoline produced during the averaging period by the refinery exclusive of any credits. (b) The refiner may include any oxygenates included in its RFG or conventional gasoline volume under §§ 80.65 and 80.101(d)(4), respectively, for the purpose of generating credits.

(c) Credits under this program are in units of ‘‘ppm-gallons’’.

(d) Refiners may generate credits for gasoline produced during an averaging period only if the annual average sulfur level for the gasoline produced during the averaging period is less than 0.90 of the refiners baseline under § 80.250 or § 80.295.


### 6833 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(e) Credits generated in accordance with paragraph (a) of this section must be identified by the year of creation.

§ 80.310 How are credits generated beginning in 2004?

(a) A refiner for any refinery, or an importer, may generate credits in 2004 and thereafter if the annual average sulfur level for gasoline produced or imported for the averaging period is less than the applicable refinery or importer annual average sulfur standard for that refinery or importer in that year. (b) Credits are calculated as follows:

CR

a=V

a × (S Std ¥ S

a)

Where:

CR

a=Credits generated for the averaging period.

V

a=Total annual volume gasoline produced at a refinery or imported during the averaging period.

S std=30 ppm; or the sulfur standard for a small refinery established under § 80.240; or, for gasoline designated as GPA gasoline under § 80.219, the lesser of 150 ppm, the refinery’s or importer’s baseline calculated under § 80.295, or the refinery’s lowest annual average sulfur content for any year from 2000 through 2003 during which the refinery generated credits or
allotments.

S

a=Actual annual average sulfur level of gasoline produced at a refinery or imported during the averaging period exclusive of any credits. (c) Credits generated in accordance with this section must be identified by the year of creation.

ABT Program—Credit Use

§ 80.315 How are credits used and what

are the limitations on credit use?

(a) Credit use. Credits may be used to meet the applicable refinery or importer annual average sulfur standards under § 80.195, § 80.216, or § 80.240, provided
that:

(1) Sulfur credits used were generated pursuant to the requirements of this subpart; and

(2) The requirements of paragraphs (b) and (c) of this section are met.

(b) Credit transfers. (1) Credits obtained from other persons may be used to meet the annual average standards specified in § 80.195, § 80.216, or § 80.240 if all the following
conditions are met:

(i) The credits are generated and reported according to the requirements of this subpart.

(ii) The credits are used in compliance with the limitations regarding the appropriate periods for credit use in this subpart. (iii) Any credit transfer takes place no later than the last day of February following the calendar year averaging period when the credits are used.

(iv) No credit may be transferred more than twice: The first transfer by the refiner or importer who generated the credit may only be made to a refiner or importer who intends to use the credit; if the transferee cannot use the credit, it may make the second, and final, transfer only to a refiner or importer who intends to use the credit. In no case may
a credit be transferred more than twice before being used or terminated.

(v) The credit transferor must apply any credits necessary to meet the transferor’s applicable average standard before transferring credits to any other refiner or importer.

(vi) No credits may be transferred that would result in the transferor having a negative credit balance.

(vii) Each transferor must supply to the transferee records indicating the years the credits were generated, the identity of the refiner or importer who generated the credits, and the identity of the transferring party, if it is not the same party that generated the credits.

(2) In the case of credits that have been calculated or created improperly,
or are otherwise determined to be invalid, the following provisions apply:

(i) Where a refiner’s baseline has been
determined to be incorrect under § 80.250(c) or § 80.290(f), any credits generated, banked, used or traded must be adjusted to reflect the corrected
baseline.

(ii) Invalid credits cannot be used to achieve compliance with the transferee’s averaging standard, regardless of the transferee’s good faith
belief that the credits were valid.

(iii) The refiner or importer who used the credits, and any transferor of the credits, must adjust their credit records and reports and sulfur calculations as necessary to reflect the proper credits.

(iv) Any properly created credits existing in the transferor’s credit balance after correcting the credit balance, and after the transferor applies credits as needed to meet the average standard at the end of the compliance year, must first be applied to correct the
invalid transfers before the transferor
trades or banks the credits.

(c) Limitations on credit use. (1) Credits generated prior to 2004 may only be used for demonstrating compliance with the refinery or importer annual average standards under § 80.195 during the 2005 and 2006 averaging periods. Such credits may be used to demonstrate compliance with the standards under § 80.216 during the 2004 through 2006 averaging periods, and with the standards under § 80.240 during the 2004 through 2007 averaging periods, and the 2008 and 2009 averaging periods, if allowed under the terms of a hardship extension under § 80.265.

(2) Credits generated in 2004 or later may only be used for demonstrating compliance with standards during an averaging period within five years of the year of generation.

(3) A refiner or importer possessing credits must use all credits prior to falling into compliance deficit under § 80.205(e).

(4) Credits may not be used to meet corporate pool average standards under § 80.195.

§ 80.320 [Reserved]

§ 80.325 [Reserved]

Sampling, Testing and Retention Requirements for Refiners and Importers

§ 80.330 What are the sampling and testing requirements for refiners and importers?

(a) Sample and test each batch of gasoline. (1) Refiners and importers shall collect a representative sample from each batch of gasoline produced or imported and test each sample to
determine its sulfur content for compliance with requirements under this subpart prior to the gasoline leaving the refinery or import facility, using the sampling and testing methods provided
in this section.

(2) Except as provided in paragraph (a)(3) of this section, the requirements of this section apply beginning January 1, 2004, or January 1 of the first year of allotment or credit generation under § 80.275 or § 80.305, whichever is
earlier.

(3) Prior to January 1, 2004, for purposes of meeting the sampling and testing requirements of this section for conventional gasoline, any refiner may, prior to analysis, combine samples of gasoline from more than one batch of gasoline or blendstock and treat such composite sample as one batch of gasoline or blendstock pursuant to the requirements of § 80.101(i)(2).

(4) Any refiner who produces reformulated gasoline or conventionalgasoline using computer-controlled inline blending equipment may meet the testing requirement of paragraph (a)(1)
of this section under the terms of an exemption granted under § 80.65(f)(4).

(b) Sampling methods. For purposes of paragraph (a) of this section, refiners and importers shall sample each batch of gasoline by using one of the following
methods:


### 6834 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(1) Manual sampling of tanks and pipelines shall be performed according to the applicable procedures specified in one of the two following methods:

(i) American Society for Testing and Materials (ASTM) method D 4057–95,
entitled ‘‘Standard Practice for Manual Sampling of Petroleum and Petroleum
Products.’’

(ii) Samples collected under the applicable procedures in ASTM method D 5842–95, entitled ‘‘Standard Practice for Sampling and Handling of Fuels for Volatility Measurement,’’ may be used for measuring sulfur content if there is no contamination present that could
affect the sulfur test result.

(2) Automatic sampling of petroleum products in pipelines shall be performed according to the applicable procedures specified in ASTM method D 4177–95, entitled ‘‘Standard Practice for Automatic Sampling of Petroleum
and Petroleum Products.’’

(c) Test method for measuring the sulfur content of gasoline. (1) For purposes of paragraph (a) of this section, refiners and importers shall use the method provided in § 80.46(a)(1) to measure the sulfur content of gasoline they produce or import.

(2) Except as provided in § 80.350 and in paragraph (c)(1) of this section, any ASTM sulfur test method for liquefied fuels may be used for quality assurance testing under § 80.400, or to determine whether gasoline qualifies for a S–RGAS downstream standard, if the protocols of
the ASTM method are followed and the
alternative method is correlated to the method provided in § 80.46(a)(1).

(d) Test method for sulfur in butane. (1) Refiners and importers shall use the method provided in § 80.46(a)(2) to
measure the sulfur content of butane
when the butane constitutes a batch of gasoline.

(2) Except as provided in paragraph (d)(1) of this section, any ASTM sulfur test method for gaseous fuels may be used for quality assurance testing under §§ 80.340(b)(4) and 80.400, if the protocols of the ASTM method are
followed and the alternative method is correlated to the method provided in § 80.46(a)(2).

(e) Incorporations by reference. ASTM standard practices D 4057–95, D 4177– 95 and D 5842–95 are incorporated by reference. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Dr., West Conshohocken, PA 19428. Copies may be inspected at the Air Docket Section (LE–131), room M–1500, U.S. Environmental Protection Agency, Docket No. A–97–03, 401 M Street, SW., Washington, DC 20460, or at the Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC.

§ 80.335 What gasoline sample retention requirements apply to refiners and importers?

(a) Sample retention requirements. Beginning January 1, 2004, or January 1 of the first year allotments or credits are generated under §§ 80.275 and 80.305, whichever is earlier, any refiner or importer shall:

(1) Collect a representative portion of each sample analyzed under § 80.330(a), of at least 330 ml in volume;

(2) Retain sample portions for the most recent 20 samples collected, or for each sample collected during the most recent 21 day period, whichever is
greater;

(3) Comply with the gasoline sample handling and storage procedures under § 80.330(b) for each sample portion retained; and

(4) Comply with any request by EPA

to:

(i) Provide a retained sample portion
to the Administrator’s authorized representative; and

(ii) Ship a retained sample portion to EPA, within 2 working days of the date of the request, by an overnight shipping service or comparable means, to the address and following procedures specified by EPA, and accompanied with the sulfur test result for the sample determined under § 80.330(a).

(b) Sample retention requirement for samples subject to independent analysis requirements. (1) Any refiner or importer who meets the independent analysis requirements under § 80.65(f) for any batch of reformulated gasoline or RBOB will have met the requirements of paragraph (a) of this section, provided the independent laboratory meets the requirements of paragraph (a) of this section for the gasoline batch.

(2) For samples retained by an independent laboratory under paragraph (b) of this section, the test results required to be submitted under paragraph (a) of this section shall be the test results determined under § 80.65(e).

(c) Sampling compliance certification. Any refiner or importer shall include with each annual report filed under § 80.370, the following statement, which must accurately reflect the facts and must be signed and dated by the same person who signs the annual report:

I certify that I have made inquiries that are sufficient to give me knowledge of the procedures to collect and store gasoline samples, and I further certify that the procedures meet the requirements of the ASTM procedures required under 40 CFR

80.330.

§ 80.340 What standards and requirements apply to refiners producing gasoline by blending blendstocks into previously certified gasoline (PCG)?

(a) Any refiner who produces gasoline by blending blendstock into PCG must meet the requirements of § 80.330 to sample and test every batch of gasoline
as follows:

(1)(i) Sample and test to determine the
volume and sulfur content of the PCG prior to blendstock blending.

(ii) Sample and test to determine the
volume and sulfur content of the gasoline subsequent to blendstock blending.

(iii) Calculate the volume and sulfur content of the blendstock, by subtracting
the volume and sulfur content of the
PCG from the volume and sulfur content of the gasoline subsequent to blendstock blending. The blendstock is a batch for purposes of compliance calculations and reporting. For purposes of this paragraph (a), compliance with the applicable cap standard under § 80.195(a) shall be determined based on the sulfur content of the gasoline subsequent to blendstock blending.

(2) In the alternative, a refiner may sample and test each batch of
blendstock when received at the refinery to determine the volume and sulfur content, and treat each blendstock receipt as a separate batch for purposes of compliance calculations for the annual average sulfur standard and for reporting. This alternative applies only if every batch of blendstock used at a refinery during an averaging period has a sulfur content that is equalto, or less than, the applicable pergallon cap standard under §§ 80.195 or

80.216.

(b) Refiners who blend only butane into PCG may meet the sampling and testing requirements by using sulfur test results of the butane supplier, provided that the following requirements are also

met:

(1) The sulfur content of the butane received from the butane supplier must not exceed the following sulfur standards on a per-gallon basis as
follows:

(i) 120 ppm in 2004, and 30 ppm for 2005 and any subsequent year;

(ii) Except that the per-gallon sulfur
content of butane blended to PCG that is designated as GPA gasoline shall not exceed 150 ppm from January 1, 2004, through December 31, 2006.

(2) The refiner obtains test results from the butane supplier that
demonstrate that the sulfur content of


### 6835 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

each load of butane supplied does not exceed the applicable per-gallon sulfur standard under paragraph (b)(1) of this section through test results of samples of the butane contained in the storage
tank from which the butane blender is supplied.

(i) Testing for the sulfur content of the butane by the supplier must be subsequent to each receipt of butane into the supplier’s storage tank, or the testing must be immediately before
transfer of butane to the butane blender.

(ii) The testing must be performed by the method specified in § 80.46(a)(2).

(iii) The butane blender must obtain a copy of the butane supplier’s test results, at the time of each transfer of butane to the butane blender, that reflect
the sulfur content of each load of butane supplied to the butane blender.

(3) The sulfur content and volume of each batch of gasoline produced is that
of the butane the refiner blends into gasoline for purposes of calculating compliance with the standards in §§ 80.195 and 80.216.

(4) The refiner must conduct a quality assurance program of sampling and testing for each butane supplier that
demonstrates the butane sulfur contentdoes not exceed the applicable pergallon sulfur standard in paragraph (b)(1) of this section. The frequency of butane sampling and testing, for each butane supplier, must be one sample for every 500,000 gallons of butane received, or one sample every 3 months, whichever results in more frequent sampling.

(5) If any of the requirements of this section are not met, in whole or in part, for any butane blended into gasoline,
that butane is deemed in violation of the gasoline sulfur standards in § 80.195 or § 80.216, as applicable.

§ 80.345 [Reserved]

§ 80.350 What alternative sulfur standards and requirements apply to importers who transport gasoline by truck?

Importers who import gasoline into the United States by truck may comply with the following requirements instead of the requirements to sample and test every batch of gasoline under § 80.330,and the annual sulfur average and pergallon cap standards otherwise applicable to importers under §§ 80.195
and 80.216:

(a) Alternative standards. The imported gasoline must comply with the standards in paragraph (a)(1) or (a)(2) of
this section as follows:

(1) The applicable average standards,corporate average standards and pergallon standards under § 80.195(a)(1), except that imported gasoline designated for use in the geographic phase-in area from January 1, 2004, through December 31, 2006 must comply with an average standard of 150 ppm and a per-gallon standard of 300

ppm; or

(2) In 2004, a per-gallon standard of 120 ppm, and in 2005 and subsequent years a per-gallon standard of 30 ppm, except that imported gasoline designated for use in the geographic phase-in area from January 1, 2004, through December 31, 2006 must comply with a per-gallon standard of 150 ppm.

(b) Terminal testing. The importer may use test results for sulfur content testing conducted by the terminal operator, for gasoline contained in the storage tank from which trucks used to transport gasoline into the United States are loaded, for purposes of demonstrating compliance with the standards in paragraph (a) of this section, provided the following
conditions are met:

(1) The sampling and testing shall be performed after each receipt of gasoline into the storage tank, or immediately before each transfer of gasoline to the importer’s truck.

(2) The sampling and testing shall be performed using the methods specified in § 80.330(b) and 80.46(a)(1), respectively.

(3) At the time of each transfer of gasoline to the importer’s truck for import to the U.S., the importer must obtain a copy of the terminal test result
that indicates the sulfur content of the
truck load.

(c) Quality assurance program. The importer must conduct a quality assurance program, as specified in this paragraph, for each truck loading
terminal.

(1) Quality assurance samples must be obtained from the truck-loading terminal and tested by the importer, or by an independent laboratory, and the terminal operator must not know in advance when samples are to be
collected.

(2) The sampling and testing must be performed using the methods specified in §§ 80.330(b) and 80.46(a)(1), respectively.

(3) The quality assurance test results
for sulfur must differ from the terminal test result by no more than the ASTM reproducibility of the terminal’s test results, as determined by the following equation:

R = 105 × (( S+2)/10 4) 0.4

Where: R = ASTM reproducibility.
S = Sulfur content based on the
terminal’s test result. (4) The frequency of the quality assurance sampling and testing must be at least one sample for each fifty of an importer’s trucks that are loaded at a terminal, or one sample per month, whichever is more frequent.

(d) Party required to conduct quality assurance testing. The quality assurance program under paragraph (c) of this section shall be conducted by the importer. In the alternative, this testing may be conducted by an independent laboratory that meets the criteria under § 80.65(f)(2)(iii), provided the importer receives, no later than 21 days after the sample was taken, copies of all results
of tests conducted.

(e) Assignment of batch numbers. The importer must treat each truck load of imported gasoline as a separate batch for purposes of assigning batch numbers and maintaining records under § 80.365, and reporting under § 80.370.

(f) EPA inspections of terminals. EPA inspectors or auditors, and auditors conducting attest engagements under § 80.415, must be given full and immediate access to the truck-loading terminal and any laboratory at which samples of gasoline collected at the terminal are analyzed, and must be allowed to conduct inspections, review records, collect gasoline samples, and perform audits. These inspections or audits may be either announced or
unannounced.

(g) Certified Sulfur-FRGAS. This section does not apply to Certified
Sulfur-FRGAS.

(h) Reporting requirements. Any importer who elects to comply with the alternative standards in paragraph (a) of this section shall comply with the following requirements:

(1) All importer recordkeeping and reporting requirements under §§ 80.365 and 80.370, except as provided in paragraph (h)(2) of this section.

(2) An importer who elects to comply
with the alternative standards in paragraph (a)(2) of this section must certify in the annual report whether it is in compliance with the applicable per-gallon batch standard set forth in paragraph (a)(2) of this section, in lieu of providing the information required by § 80.370(a) regarding annual average sulfur content and compliance with the average standard under § 80.195.

(i) Effect of noncompliance. If any of the requirements of this section are not met, all gasoline imported by the truck importer during the time any requirements are not met is deemed in violation of the gasoline sulfur average and per-gallon cap standards in § 80.195 or § 80.216, as applicable. Additionally, if any requirement is not met, EPA may notify the importer of the violation and,


### 6836 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

if the requirement is not fulfilled within 10 days of notification, the truck importer may not in the future use the sampling and testing provisions in this section in lieu of the provisions in § 80.330.

§ 80.355 [Reserved]

Recordkeeping and Reporting Requirements

§ 80.360 [Reserved]

§ 80.365 What records must be kept?

(a) Records that must be kept. Beginning January 1, 2004, any person who produces, imports, sells, offers for sale, dispenses, distributes, supplies, offers for supply, stores, or transports gasoline, shall keep records that contain the following information:

(1) The product transfer document information required under §§ 80.77, 80.106, 80.210 and 80.219; and

(2) For any sampling and testing for sulfur content required under this subpart:

(i) The location, date, time and storage
tank or truck identification for each sample collected;

(ii) The name and title of the person who collected the sample and the person who performed the test;

(iii) The results of the test as originally printed by the testing apparatus, or where no printed result is produced, the results as originally recorded by the person who performed the test; and

(iv) Any record that contains a test result for the sample that is not identical to the result recorded under paragraph (a)(2)(iii) of this section.

(b) Additional records that refiners and importers must keep. Beginning January 1, 2004, or January 1 of the first year allotments or credits are generated under § 80.275 or § 80.305, whichever is earlier, any refiner for each of its refineries, and any importer for the gasoline it imports, shall keep records that include the following information:

(1) For each batch of gasoline produced or imported:

(i) The batch volume; (ii) The batch number assigned under § 80.65(d)(3) and the appropriate designation under paragraph (b)(1)(i) of this section; except that if composite samples of conventional gasoline representing multiple batches produced subsequent to December 31, 2003, aretested under § 80.101(i)(2) for antidumping compliance purposes, for purposes of this subpart a separate batch number must be assigned to each batch using the batch numbering procedures under § 80.65(d)(3);

(iii) The date of production or importation; and (iv) If appropriate, the designation of the batch as GPA gasoline under § 80.219, California gasoline under § 80.375, exempt gasoline for research and development under § 80.380, or for export outside the United States.

(2) Information regarding credits and allotments, separately kept for credits and for allotments; separately kept according to the year of creation for the credits and for the allotments; and for credit generation or use starting in 2004, separately kept for GPA gasoline and other gasoline. Information shall be kept separately for different types of allotments and credits generated under §§ 80.275(e)(1), 80.275(e)(2), 80.305 and

80.310:

(i) The number in the refiner’s or importer’s possession at the beginning of the averaging period;

(ii) The number generated; (iii) The number used; (iv) If any were obtained from or transferred to other parties, for each other party its name, its EPA refiner or importer registration number, and the number obtained from, or transferred to, the other party;

(v) The number that expired at the end of the averaging period;

(vi) The number of allotments, by type, that were converted into credits under § 80.275(e);

(vii) The number in the refiner’s or importer’s possession that will carry over into the subsequent averaging period; and

(viii) Contracts or other commercial
documents that establish each transfer
of credits and allotments from the
transferor to the transferee.

(3) The calculations used to determine the applicable refiner baseline under § 80.250 or § 80.295.

(4) The calculations used to determine compliance with the applicable sulfur average standards of § 80.195, § 80.216, § 80.240, or § 80.270.

(5) The calculations used to determine
the number of credits or allotments generated under § 80.305, § 80.310 or § 80.275.

(6) The calculations used to determine any applicable adjusted cap standard under § 80.195(d).

(7) A copy of all reports submitted to EPA under § 80.370.

(c) Additional records importers must keep. Any importer shall keep records that identify and verify the source of
each batch of certified Sulfur-FRGAS
and non-certified Sulfur-FRGAS imported and demonstrate compliance with the requirements for importers under § 80.410(o).

(d) Length of time records must be kept. The records required in this section shall be kept for five years from the date they were created; except that: (1) Transfers of credits and
allotments. Records relating to credit and allotment transfers, except as provided in paragraph (d)(2) of this section, shall be kept by the transferor for 5 years from the date the credits or allotments are transferred, and shall be kept by the transferee for 5 years from
the date the credits or allotments were transferred, used or terminated,
whichever is later.

(2) Early credits. (i) Where the party generating the credits does not transfer the credits, records must be kept for 5 years from the date of creation, use or
termination whichever is later.

(ii) Where early credits are transferred, records relating to such credits shall be kept by both parties for 5 years from the date the credits were transferred, used or terminated,
whichever is later.

(e) Make records available to EPA. On request by EPA the records required in paragraphs (a), (b) and (c) of this section shall be provided to the Administrator’s authorized representative. For records that are electronically generated or maintained the equipment and software necessary to read the records shall be made available, or if requested by EPA,
electronic records shall be converted to paper documents which shall be provided to the Administrator’s authorized representative.

§ 80.370 What are the sulfur reporting requirements?

Beginning with the 2004 averaging period, or the first year credits or allotments are generated under § 80.275 or § 80.305, whichever is earlier, and continuing for each averaging period thereafter, any refiner or importer shall submit to EPA annual reports that contain the information required in this section, and such other information as EPA may require.

(a) Refiner and importer annual reports. Any refiner, for each of its refineries, and any importer for the gasoline it imports, shall submit a report for each calendar year averaging period that includes the following information, and in the case of a refiner or importer producing or importing both GPA gasoline and other gasoline, the information shall be separately reported:

(1) The EPA importer, or refiner and refinery facility registration numbers;

(2) The applicable baseline, average standard, and adjusted cap standard as
follows:

(i) For the years 2000 through 2003, the applicable baseline under § 80.250 or § 80.295.

(ii) For the 2004 averaging period and subsequent averaging periods:


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(A) All applicable average standards under § 80.195, § 80.216, § 80.240 or § 80.270;

(B) All applicable adjusted cap standards under § 80.195(d), with the 2005 report identifying both the 2004 and 2005 applicable adjusted cap standards;

(3) The total volume of gasoline produced or imported;

(4) The annual average sulfur content of the gasoline produced or imported;

(5) The annual average sulfur level after inclusion of any credits and allotments;

(6) Information, separately provided, for credits and allotments, and separately by year of creation, as
follows:

(i) The number of credits and allotments at the beginning of the averaging period;

(ii) The number of credits and allotments generated;

(iii) The number of credits and allotments used;

(iv) If any credits or allotments were
obtained from or transferred to other parties, for each other party its name and EPA refiner or importer registration number, and the number of credits or
allotments obtained from or transferred to the other party;

(v) The number of credits and allotments that expired at the end of the averaging period;

(vi) The number of credits and allotments that will carry over into the subsequent averaging period; and

(vii) The number of each type of allotments converted to credits;

(7) For each batch of gasoline produced or imported during the averaging period:

(i) The batch number assigned under § 80.65(d)(3) and the appropriate designation under § 80.365; except that if composite samples of conventional gasoline representing multiple batches produced subsequent to December 31, 2003, are tested under § 80.101(i)(2) for anti-dumping compliance purposes, for purposes of this subpart a separate batch number must be assigned to each batch using the batch numbering procedures under § 80.65(d)(3);

(ii) The date the batch was produced; (iii) The volume of the batch; and (iv) The sulfur content of the batch as determined under § 80.330; and

(8) When submitting reports under this paragraph (a), any importer shall
exclude certified Sulfur-FRGAS.

(b) Additional reporting requirements for importers. Any importer shall reportthe following information for SulfurFRGAS imported during the averaging period:

(1) The EPA refiner and refinery registration numbers of each foreign refiner and refinery where the certified Sulfur-FRGAS was produced; and

(2) The total gallons of certified
Sulfur-FRGAS and non-certified SulfurFRGAS imported from each foreign refiner and refinery.

(c) Corporate pool average reports. (1) Annual reports filed under this section for the 2004 and 2005 averaging periods must include the party’s corporate pool average as determined under § 80.205.

(2) If the party submitting the annual report under paragraph (c)(1) of this
section is a refiner with more than one refinery or is a refiner who also imports gasoline, then for the purposes of this paragraph, the party shall report the information required for individual refineries and for importers under paragraph (a) of this section, also in the aggregate for all the gasoline produced and imported during the calendar year.

(3) Refiners and importers exempted from corporate pool standards under § 80.216 or § 80.240 are exempt from reporting the information required under paragraphs (c)(1) and (c)(2) of this

section.

(d) Report submission. Any annual report required under this section shall
be:

(1) Signed and certified as meeting all of the applicable requirements of this subpart by the owner or a responsible corporate officer of the refiner or importer; and

(2) Submitted to EPA no later than the last day of February for the prior calendar year averaging period.

(f) Attest reports. Attest reports for refiner and importer attest engagements required under § 80.415 shall be submitted to the Administrator by May 31 of each year for the prior calendar year averaging period.

§§ 80.371—80.373 [Reserved]

Exemptions

§ 80.374 What if a refiner or importer is unable to produce gasoline conforming to the requirements of this subpart?

In appropriate extreme and unusual circumstances ( e.g., natural disaster or Act of God) which are clearly outside the control of the refiner or importer
and which could not have been avoided by the exercise of prudence, diligence, and due care, EPA may permit a refiner or importer, for a brief period, to distribute gasoline which does not meet the requirements of this subpart provided the refiner or importer meets all the criteria, requirements and conditions contained in § 80.73 (a) through (e). § 80.375 What requirements apply to California gasoline?

(a) Definition. For purposes of this subpart California gasoline means any gasoline designated by the refiner as for
use in California.

(b) California gasoline exemption. California gasoline that complies with all the requirements of this section is exempt from all other provisions of this subpart.

(c) Requirements for California gasoline. The requirements are:

(1) Each batch of California gasoline must be designated as such by its refiner or importer;

(2) Designated California gasoline must be kept segregated from gasoline that is not California gasoline, at all points in the distribution system;

(3) Designated California gasoline must ultimately be used in the State of California and not used elsewhere;

(4) In the case of California gasoline produced outside the State of California,
the transferors and transferees must meet the product transfer document requirements under § 80.81(g); and

(5) Gasoline that is ultimately used in any part of the United States outside of the State of California must comply with the standards and requirements of this subpart, regardless of any designation as California gasoline.

(d) Use of California test methods and off site sampling procedures. In the case of any gasoline that is not California gasoline and that is either produced at a refinery located in the State of California or is imported from outside
the United States into the State of California, the refiner or importer may, with regard to such gasoline:

(1) Use the sampling and testing methods approved in Title 13 of the California Code of Regulations instead of the sampling and testing methods required under § 80.330; and

(2) Determine the sulfur content of gasoline at off site tankage as permitted in § 80.81(h)(2).

§ 80.380 What are the requirements for obtaining an exemption for gasoline used for research, development or testing purposes?

Any person may request an exemption from the provisions of this subpart for gasoline used for research, development or testing (‘‘R&D’’) purposes by submitting to EPA an application that includes all the information listed in paragraph (b) of
this section.

(a) Criteria for an R&D exemption. For an R&D exemption to be granted, the proposed test program must:

(1) Have a purpose that constitutes an appropriate basis for exemption;


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(2) Necessitate the granting of an exemption;

(3) Be reasonable in scope; and (4) Have a degree of control consistent with the purpose of the program and EPA’s monitoring requirements.

(b) Information required to be
submitted. To demonstrate each of the four elements in paragraphs (a)(1) through (4) of this section, the application required under this section must include the following information:

(1) A statement of the purpose of the program demonstrating that the program has an appropriate R&D purpose.

(2) An explanation of why the stated purpose of the program cannot be achieved in a practicable manner without performing one or more of the prohibited acts under § 80.385.

(3) To demonstrate the reasonableness of the scope of the program:

(i) An estimate of the program’s beginning and ending dates;

(ii) An estimate of the maximum number of vehicles and engines involved in the program, and the number of miles and engine hours that will be accumulated on each;

(iii) The sulfur content of the gasoline expected to be used in the program; and

(iv) The quantity of gasoline that exceeds the applicable sulfur standard that is expected to be used in the

program.

(4) With regard to control, a demonstration that the program affords EPA a monitoring capability, including

at a minimum:

(i) A description of the technical and operational aspects of the program;

(ii) The site(s) of the program (including street address, city, county, State, and ZIP code);

(iii) The manner in which information on vehicles and engines used in the program will be recorded and made available to EPA;

(iv) The manner in which results of the program will be recorded and made available to EPA;

(v) The manner in which information on the gasoline used in the program (including quantity, sulfur content, name, address, telephone number and contact person of the supplier, and the date received from the supplier), will be recorded and made available to EPA;

(vi) The manner in which distribution pumps will be labeled to insure proper use of the gasoline where appropriate;

(vii) The name, address, telephone number and title of the person(s) in the organization requesting an exemption
from whom further information on the application may be obtained; and

(viii) The name, address, telephone number and title of the person(s) in the organization requesting an exemption who is responsible for recording and making available the information specified in paragraphs (b)(4)(iii), (iv) and (v) of this section, and the location
in which such information will be
maintained.

(c) Additional requirements. (1) The product transfer documents associated with R&D gasoline must identify the gasoline as such, and must state that the gasoline is to be used only for research, development, or testing purposes.

(2) The R&D gasoline must be designated by the refiner or importer as exempt R&D gasoline.

(3) The R&D gasoline must be kept segregated from non-exempt gasoline at all points in the distribution system of the gasoline.

(4) The R&D gasoline must not be sold, distributed, offered for sale or distribution, dispensed, supplied, offered for supply, transported to or from, or stored by a gasoline retailoutlet, or by a wholesale purchaserconsumer facility, unless the wholesale purchaser-consumer facility is associated with the R&D program that uses the gasoline.

(d) Memorandum of exemption. The Administrator will grant an R&D exemption upon a demonstration that the requirements of this section have been met. The R&D exemption will be granted in the form of a memorandum of exemption signed by the applicant and the Administrator (or delegate), which may include such terms and
conditions as the Administrator determines necessary to monitor the exemption and to carry out the purposes of this section, including restoration of
motor vehicle emissions control systems. Any violation of such a term or condition of the exemption or any requirement under this section will cause the exemption to be void ab initio.

(e) Effects of exemption. Gasoline that is subject to an R&D exemption under this section is exempt from other provisions of this subpart provided that the gasoline is used in a manner that complies with the memorandum of exemption granted under paragraph (d)
of this section.

Violation Provisions

§ 80.385 What acts are prohibited under the gasoline sulfur program?

No person shall: (a) Averaging violation. Produce or import gasoline that does not comply with the applicable sulfur average standard under § 80.195, § 80.216 or § 80.240.

(b) Cap standard violation. Produce, import, sell, offer for sale, dispense, supply, offer for supply, store or transport gasoline that does not comply with the applicable sulfur cap standard under § 80.195, § 80.216, § 80.210, § 80.220 or § 80.240.

(c) Causing an averaging, cap standard, or geographic phase-in area (GPA) use violation. Cause another person to commit an act in violation of paragraph (a), (b), or (f) of this section.

(d) Causing violating gasoline to be in the distribution system. Cause gasoline to be in the distribution system which does not comply with an applicable sulfur cap standard under § 80.195, § 80.210, § 80.216, § 80.220 or § 80.240; a sulfur average standard under § 80.195, § 80.216 or § 80.240; or a GPA use prohibition under § 80.219(c).

(e) Denatured ethanol violation. Blend into gasoline denatured ethanol with a sulfur content higher than 30 ppm.

(f) GPA use violation. Produce, import, sell, offer for sale, dispense, supply, offer for supply, store or transport gasoline that does not comply with a GPA use prohibition under § 80.219(c).

§ 80.390 What evidence may be used to determine compliance with the prohibitions and requirements of this subpart and liability for violations of this subpart?

(a) Compliance with the sulfur standards of this subpart shall be
determined based on the sulfur level of the gasoline, measured using the methodologies specified in §§ 80.330(b) and 80.46(a). Any evidence or information, including the exclusive use of such evidence or information, may be
used to establish the sulfur level of gasoline if the evidence or information
is relevant to whether the sulfur level of gasoline would have been in compliance with the standards if the appropriate sampling and testing methodology had been correctly performed. Such evidence may be obtained from any source or location and may include, but is not limited to, test results using methods other than those specified in §§ 80.330(b) and 80.46(a), business records, and
commercial documents.

(b) Determinations of compliance with the requirements of this subpart other than the sulfur standards, and determinations of liability for any violation of this subpart, may be based on information obtained from any
source or location. Such information may include, but is not limited to,
business records and commercial
documents.

§ 80.395 Who is liable for violations under the gasoline sulfur program?

(a) Persons liable for violations of prohibited acts. (1) Averaging violation.


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Any refiner or importer who violates § 80.385(a) is liable for the violation.

(2) Causing an averaging violation. Any refiner, importer, distributor, reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate blender who causes another party to violate § 80.385(a), is liable for a violation of § 80.385(c).

(3) Cap standard violation. Any refiner, importer, distributor, reseller,carrier, retailer, wholesale purchaserconsumer, or oxygenate blender who owned, leased, operated, controlled or supervised a facility where a violation of § 80.385 (b) occurred, is deemed in violation of § 80.385(b).

(4) Causing a cap standard violation. Any refiner, importer, distributor, reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate blender who produced, imported, sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, or caused the transportation or storage of gasoline that violates § 80.385(b), is deemed in violation of § 80.385(c).

(5) GPA use violation. Any refiner, importer, distributor, reseller, carrier, retailer, wholesale purchaser-consumer, or oxygenate blender who produced, imported, sold, offered for sale, dispensed, supplied, offer for supply, stored, transported, or caused the transportation or storage of gasoline that violates § 80.385(f), is deemed in violation of § 80.385(f).

(6) Causing a GPA use violation. Any refiner, importer, distributor, reseller,carrier, retailer, wholesale purchaserconsumer, or oxygenate blender who causes another party to violate § 80.385(f), is deemed liable for a violation of § 80.385(c).

(7) Branded refiner/importer liability. Any refiner or importer whose corporate, trade, or brand name, or whose marketing subsidiary’s corporate, trade, or brand name appeared at a facility where a violation of § 80.385(b) or (f) occurred, is deemed in violation of § 80.385(b) or (f), as applicable.

(8) Causing violating gasoline to be in the distribution system. Any refiner, importer, distributor, reseller, carrier, or oxygenate blender, who owned, leased, operated, controlled or supervised a facility from which gasoline was released into the distribution system which does not comply with an applicable sulfur cap standard, a sulfur averaging standard, or a GPA use prohibition, is deemed in violation of § 80.385(d).

(9) Carrier causation. In order for a carrier to be liable under paragraph (a)(2), (4), (6), or (8) of this section, EPA must demonstrate, by reasonably specific showing by direct or circumstantial evidence, that the carrier
caused the violation.

(10) Denatured ethanol violation. Any oxygenate blender who violates § 80.385(e) is liable for the violation.

(11) Parent corporation liability. Any parent corporation is liable for any violations of this subpart that are committed by any of its wholly-owned
subsidiaries.

(12) Joint venture liability. Each partner to a joint venture is jointly and severally liable for any violation of this subpart that occurs at the joint venture facility or is committed by the joint venture operation.

(b) Persons liable for failure to meet other provisions of this subpart. (1) Any refiner, importer, distributor, reseller, carrier, wholesale purchaser-consumer, retailer, or oxygenate blender who fails to meet a provision of this subpart not addressed in paragraph (a) of this
section is liable for a violation of that provision.

(2) Any refiner, importer, distributor,reseller, carrier, wholesale purchaserconsumer, retailer, or oxygenate blender who caused another person to fail to meet a requirement of this subpart not addressed in paragraph (a) of this section, is liable for causing a violation of that provision.

§ 80.400 What defenses apply to persons deemed liable for a violation of a prohibited

act?

(a) Any person deemed liable for a violation of a prohibition under § 80.395 (a)(3) through (8), will not be deemed in violation if the person demonstrates
that:

(1) The violation was not caused by the person or the person’s employee or agent; and

(2) The person conducted a quality assurance sampling and testing program, as described in paragraph (d) of this section. A carrier may rely on the quality assurance program carried out by another party, including the party who owns the gasoline in question, provided that the quality assurance program is carried out properly.Retailers and wholesale purchaserconsumers are not required to conduct quality assurance programs.

(b) In the case of a violation found at a facility operating under the corporate,
trade or brand name of a refiner or importer, or a refiner’s or importer’s marketing subsidiary, the refiner or importer must show, in addition to the defense elements required under paragraphs (a)(1) and (2) of this section, that the violation was caused by:

(1) An act in violation of law (other than the Clean Air Act or this part 80), or an act of sabotage or vandalism; (2) The action of any refiner, importer, retailer, distributor, reseller, oxygenate blender, carrier, retailer or wholesale purchaser-consumer in violation of a contractual agreement between the branded refiner or importer and the person designed to prevent such action, and despite periodic sampling and testing by the branded refiner or importer to ensure compliance with such contractual obligation; or

(3) The action of any carrier or other distributor not subject to a contract with the refiner or importer, but engaged for transportation of gasoline, despite specifications or inspections of procedures and equipment which are reasonably calculated to prevent such

action.

(c) Under paragraph (a) of this section for any person to show that a violation was not caused by that person, or under paragraph (b) of this section to show that a violation was caused by any of the specified actions, the person must demonstrate by reasonably specific showing, by direct or circumstantial evidence, that the violation was caused or must have been caused by another person and that the person asserting the
defense did not contribute to that other person’s causation.

(d) Quality assurance and testing

program. To demonstrate an acceptable quality assurance and testing program under paragraph (a)(2) of this section, a person must present evidence of the following:

(1) A periodic sampling and testing program to ensure the gasoline the person sold, dispensed, supplied, stored, or transported, meets the applicable sulfur standard; and

(2) On each occasion when gasoline is found not in compliance with the applicable sulfur standard:

(i) The person immediately ceases selling, offering for sale, dispensing, supplying, offering for supply, storing or transporting the non-complying product; and

(ii) The person promptly remedies the
violation and the factors that caused the violation (for example, by removing the non-complying product from the distribution system until the applicable standard is achieved and taking steps to prevent future violations of a similar nature from occurring).

(3) For any carrier who transports gasoline in a tank truck, the quality assurance program required under this paragraph (d) need not include periodic sampling and testing of gasoline in the tank truck, but in lieu of such tank truck sampling and testing, the carrier shall demonstrate evidence of an oversight program for monitoring compliance with the requirements of this subpart


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relating to the transport or storage of gasoline by tank truck, such as appropriate guidance to drivers regarding compliance with the applicable sulfur standard and product transfer document requirements, and the periodic review of records received in the ordinary course of business concerning gasoline quality and delivery.

§ 80.405 What penalties apply under this subpart?

(a) Any person liable for a violation under § 80.395 is subject to civil penalties as specified in section 205 of the Clean Air Act for every day of each
such violation and the amount of economic benefit or savings resulting
from each violation.

(b) Any person liable under § 80.395(a)(1) or (2) for a violation of the applicable sulfur averaging standard or causing another party to violate that standard during any averaging period, is subject to a separate day of violation for each and every day in the averaging period. Any person liable under § 80.395(b) for a failure to fulfill any requirement for credit or allotment generation, transfer, use, banking, or deficit correction, is subject to a separate day of violation for each and every day in the averaging period in
which invalid credits or allotments are generated or used.

(c)(1) Any person liable under § 80.395(a)(3), (4), (5), or (6) for a violation of an applicable sulfur per gallon cap standard under § 80.195, § 80.210, § 80.216, § 80.220 or § 80.240, a GPA use prohibition under § 80.219(c), or of causing another party to violate a cap standard or a GPA use prohibition, is subject to a separate day of violation for each and every day the non-complying gasoline remains any place in the gasoline distribution
system.

(2) Any person liable under § 80.395(a)(8) for causing gasoline to be in the distribution system which does not comply with an applicable sulfur cap standard, a sulfur averaging standard, or a GPA use prohibition, is subject to a separate day of violation foreach and every day that the noncomplying gasoline remains any place in the gasoline distribution system.

(3) For purposes of paragraph (c) of this section, the length of time the gasoline in question remained in the gasoline distribution system is deemed to be twenty-five days, unless a person subject to liability or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, that the non-complying gasoline remained in the gasoline distribution system for fewer than or more than twenty-five days.

(d) Any person liable under § 80.395(b) for failure to meet, or causing a failure to meet, a provision of this subpart is liable for a separate day of violation for each and every day such provision remains unfulfilled.

Provisions for Foreign Refiners With
Individual Sulfur Baselines

§ 80.410 What are the additional requirements for gasoline produced at foreign refineries having individual small refiner sulfur baselines, foreign refineries granted temporary relief under § 80.270, or baselines for generating credits during 2000 through 2003?

(a) Definitions. (1) A foreign refinery is a refinery that is located outside the United States, the Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa, and the
Commonwealth of the Northern Mariana Islands (collectively referred to in this section as ‘‘the United States’’).

(2) A foreign refiner is a person who
meets the definition of refiner under § 80.2(i) for a foreign refinery.

(3) A small foreign refiner is a refiner
that meets the definition of a small refiner under § 80.225.

(4) ‘‘Sulfur-FRGAS’’ means gasoline produced at a foreign refinery that has been assigned an individual refinery sulfur baseline under §§ 80.250 or 80.295, or has been granted temporary relief under § 80.270, and that is imported into the United States.

(5) ‘‘Non-Sulfur-FRGAS’’ means gasoline that is produced at a foreign refinery that has not been assigned an individual refinery sulfur baseline, gasoline produced at a foreign refinery with an individual refinery sulfur baseline that is not imported into the United States, and gasoline produced at a foreign refinery with an individual sulfur baseline during a year when the foreign refiner has opted to not participate in the Sulfur-FRGAS program under paragraph (c)(3) of this

section.

(6) ‘‘Certified Sulfur-FRGAS’’ means Sulfur-FRGAS the foreign refiner intends to include in the foreign refinery’s sulfur compliance calculations under § 80.205 pursuant to § 80.240 or § 80.270 or credit calculations under §§ 80.305 or 80.310
and allotment calculations under § 80.275(a), and does include in these compliance calculations when reported

to EPA.

(7) ‘‘Non-Certified Sulfur-FRGAS’’
means Sulfur-FRGAS that is not
Certified Sulfur-FRGAS.

(b) Baseline establishment. Any foreign refiner who does not have an approved refinery baseline under § 80.94 may submit a petition to the Administrator for an individual refinery sulfur baseline pursuant to §§ 80.245 and 80.250, a baseline for generating credits or allotments under §§ 80.290 and 80.295, or a baseline for temporary refinery relief under §§ 80.270 and

80.295.

(1) The refiner shall follow the procedures specified in §§ 80.91 through 80.93 to establish the volume and sulfur content of gasoline that was produced at the foreign refinery and imported into the United States during 1997 and 1998 for purposes of establishing baselines under § 80.250 or § 80.295.

(2) In making determinations for foreign refinery baselines EPA will consider all information supplied by a foreign refiner, and in addition may rely on any and all appropriate assumptions necessary to make such determinations.

(3) Where a foreign refiner submits a petition that is incomplete or inadequate to establish an accurate baseline, and the refiner fails to cure this defect after a request for more information, EPA will not assign an individual refinery sulfur baseline.

(c) General requirements for foreign refiners with individual refinery sulfur
baselines. A foreign refiner of a refinery that has been assigned an individual sulfur baseline under § 80.250 or § 80.295 must designate all gasoline produced at the foreign refinery that is exported to the United States as either
Certified Sulfur-FRGAS or as NonCertified Sulfur-FRGAS, except as provided in paragraph (c)(3) of this

section.

(1) In the case of Certified SulfurFRGAS, the foreign refiner must meet all provisions that apply to refiners under this subpart H.

(2) In the case of Non-Certified SulfurFRGAS, the foreign refiner shall meet all the following provisions, except the foreign refiner shall substitute the name
Non-Certified Sulfur-FRGAS for the names ‘‘reformulated gasoline’’ or ‘‘RBOB’’ wherever they appear in the following provisions:

(i) The designation requirements in this section;

(ii) The recordkeeping requirements under § 80.365;

(iii) The reporting requirements in § 80.370 and this section;

(iv) The product transfer document requirements in this section;

(v) The prohibitions in this section and § 80.385; and

(vi) The independent audit requirements under § 80.415, paragraph (h) of this section, §§ 80.125 through


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80.127, § 80.128(a),(b),(c),(g) through (i), and § 80.130.

(3)(i) Any foreign refiner that generates sulfur credits under § 80.305 during the period 2000 through 2003, or allotments under § 80.275(a) during 2003, and any small refiner generating credits under § 80.310, shall designate
all Sulfur-FRGAS as Certified SulfurFRGAS for any year that such credits are generated.

(ii) Any foreign refiner that has been assigned an individual sulfur baseline for a foreign refinery under § 80.250 or § 80.295 may elect to classify no gasoline imported into the United States as Sulfur-FRGAS, provided the foreign
refiner notifies EPA of the election no later than November 1 of the prior calendar year.

(iii) An election under paragraph (c)(3)(ii) of this section shall:

(A) Apply to an entire calendar year averaging period, and apply to all gasoline produced during the calendar year at the foreign refinery that is used in the United States; and

(B) Remain in effect for each succeeding calendar year averaging period, unless and until the foreign
refiner notifies EPA of a termination of the election. The change in election shall take effect at the beginning of the next calendar year.

(d) Designation, product transfer documents, and foreign refiner certification. (1) Any foreign refiner of a foreign refinery that has been assigned
an individual sulfur baseline must designate each batch of Sulfur-FRGAS as such at the time the gasoline is produced, unless the refiner has elected to classify no gasoline exported to the
United States as Sulfur-FRGAS under paragraph (c)(3)(i) of this section.

(2) On each occasion when any person transfers custody or title to any Sulfur-FRGAS prior to its being imported into the United States, it must include the following information as part of the product transfer document
information in this section:

(i) Identification of the gasoline as
Certified Sulfur-FRGAS or as NonCertified Sulfur-FRGAS; and

(ii) The name and EPA refinery registration number of the refinery where the Sulfur-FRGAS was produced.

(3) On each occasion when SulfurFRGAS is loaded onto a vessel or other transportation mode for transport to the United States, the foreign refiner shall prepare a certification for each batch of
the Sulfur-FRGAS that meets the following requirements:

(i) The certification shall include the report of the independent third party under paragraph (f) of this section, and the following additional information: (A) The name and EPA registration number of the refinery that produced the Sulfur-FRGAS;

(B) The identification of the gasoline
as Certified Sulfur-FRGAS or NonCertified Sulfur-FRGAS;

(C) The volume of Sulfur-FRGAS being transported, in gallons;

(D) In the case of Certified SulfurFRGAS:

( 1 ) The sulfur content as determined under paragraph (f) of this section; and

( 2) A declaration that the SulfurFRGAS is being included in the compliance calculations under § 80.205 or credit calculations under § 80.305 or allotments under § 80.275(a) for therefinery that produced the SulfurFRGAS.

(ii) The certification shall be made part of the product transfer documents
for the Sulfur-FRGAS.

(e) Transfers of Sulfur-FRGAS to nonUnited States markets. The foreign refiner is responsible to ensure that all gasoline classified as Sulfur-FRGAS is imported into the United States. Aforeign refiner may remove the SulfurFRGAS classification, and the gasoline need not be imported into the United States, but only if:

(1)(i) The foreign refiner excludes: (A) The volume of gasoline from the refinery’s compliance calculations under § 80.205; and

(B) In the case of Certified SulfurFRGAS, the volume and sulfur content of the gasoline from the compliance calculations under § 80.205 or credit calculations under § 80.305.

(ii) The exclusions under paragraph (e)(1)(i) of this section shall be on the
basis of the sulfur content and volumes determined under paragraph (f) of this section; and

(2) The foreign refiner obtains
sufficient evidence in the form of documentation that the gasoline was not imported into the United States.

(f) Load port independent sampling, testing and refinery identification. (1)
On each occasion Sulfur-FRGAS is loaded onto a vessel for transport to the United States a foreign refiner shall have an independent third party:

(i) Inspect the vessel prior to loading and determine the volume of any tank bottoms;

(ii) Determine the volume of SulfurFRGAS loaded onto the vessel (exclusive of any tank bottoms present before vessel loading);

(iii) Obtain the EPA-assigned registration number of the foreign refinery;

(iv) Determine the name and country of registration of the vessel used to transport the Sulfur-FRGAS to the United States; and (v) Determine the date and time the vessel departs the port serving the foreign refinery.

(2) On each occasion Certified SulfurFRGAS is loaded onto a vessel for transport to the United States a foreign refiner shall have an independent third party:

(i) Collect a representative sample of
the Certified Sulfur-FRGAS from each vessel compartment subsequent to loading on the vessel and prior to departure of the vessel from the port serving the foreign refinery;

(ii) Prepare a volume-weighted vessel composite sample from the compartment samples, and determine the value for sulfur using the methodology specified in § 80.330 by:

(A) The third party analyzing the sample; or

(B) The third party observing the foreign refiner analyze the sample;

(iii) Review original documents that reflect movement and storage of the
certified Sulfur-FRGAS from the refinery to the load port, and from this
review determine:

(A) The refinery at which the SulfurFRGAS was produced; and

(B) That the Sulfur-FRGAS remained segregated from:

( 1 ) Non-Sulfur-FRGAS and NonCertified Sulfur-FRGAS; and

( 2) Other Certified Sulfur-FRGAS produced at a different refinery.

(3) The independent third party shall submit a report:

(i) To the foreign refiner containing the information required under paragraphs (f)(1) and (2) of this section, to accompany the product transfer documents for the vessel; and

(ii) To the Administrator containing the information required under paragraphs (f)(1) and (2) of this section, within thirty days following the date of the independent third party’s inspection. This report shall include a description of the method used to determine the identity of the refinery at which the gasoline was produced, assurance that the gasoline remained segregated as specified in paragraph (n)(1) of this section, and a description of the gasoline’s movement and storage between production at the source refinery and vessel loading.

(4) The independent third party must: (i) Be approved in advance by EPA, based on a demonstration of ability to perform the procedures required in this paragraph (f);

(ii) Be independent under the criteria specified in § 80.65(e)(2)(iii); and

(iii) Sign a commitment that contains the provisions specified in paragraph (i) of this section with regard to activities,
facilities and documents relevant to


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compliance with the requirements of this paragraph (f).

(g) Comparison of load port and port of entry testing. (1)(i) Except as described in paragraph (g)(1)(ii) of this section, any foreign refiner and any United States importer of Certified Sulfur-FRGAS shall compare the results from the load port testing under paragraph (f) of this section, with the port of entry testing as reported under paragraph (o) of this section, for the volume of gasoline and the sulfur value.

(ii) Where a vessel transporting
Certified Sulfur-FRGAS off loads this gasoline at more than one United States port of entry, and the conditions of paragraph (g)(2)(i) of this section are met at the first United States port of entry, the requirements of paragraph (g)(2) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner, that meets the requirements of paragraph (s) of this section, that the vessel has not loaded any gasoline or blendstock between the first United States port of entry and the subsequent port of entry.

(2)(i) The requirements of this paragraph (g)(2) apply if:

(A) The temperature-corrected volumes determined at the port of entry and at the load port differ by more than one percent; or

(B) The sulfur value determined at the port of entry is higher than the sulfur value determined at the load port, and the amount of this difference is greater than the reproducibility amount specified for the port of entry test result by the American Society of Testing and Materials (ASTM).

(ii) The United States importer and the foreign refiner shall treat thegasoline as Non-Certified SulfurFRGAS, and the foreign refiner shall exclude the gasoline volume and properties from its gasoline sulfur compliance calculations under § 80.205.

(h) Attest requirements. The following additional procedures shall be carriedout by any foreign refiner of SulfurFRGAS as part of the applicable attest engagement for each foreign refinery under § 80.415:

(1) The inventory reconciliation analysis under § 80.128(b) and the tender analysis under § 80.128(c) shall
include Non-Sulfur-FRGAS in addition to the gasoline types listed in § 80.128(b) and (c).

(2) Obtain separate listings of all tenders of Certified Sulfur-FRGAS, and of Non-Certified Sulfur-FRGAS. Agree
the total volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.128(b), and to the volumes determined by the third party under paragraph (f)(1) of this

section.

(3) For each tender under paragraph (h)(2) of this section where the gasoline is loaded onto a marine vessel, report as a finding the name and country of registration of each vessel, and the
volumes of Sulfur-FRGAS loaded onto
each vessel.

(4) Select a sample from the list of vessels identified in paragraph (h)(3) of this section used to transport Certified Sulfur-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:

(i) Obtain the report of the independent third party, under paragraph (f) of this section, and of the United States importer under paragraph (o) of this section.

(A) Agree the information in these reports with regard to vessel identification, gasoline volumes and test
results.

(B) Identify, and report as a finding, each occasion the load port and port of entry parameter and volume results differ by more than the amounts allowed in paragraph (g) of this section, and determine whether the foreign refiner adjusted its refinery calculations as required in paragraph (g) of this

section.

(ii) Obtain the documents used by the independent third party to determine transportation and storage of the
Certified Sulfur-FRGAS from the refinery to the load port, under paragraph (f) of this section. Obtain tank activity records for any storage tank
where the Certified Sulfur-FRGAS is stored, and pipeline activity records for any pipeline used to transport the Certified Sulfur-FRGAS, prior to being
loaded onto the vessel. Use these
records to determine whether the Certified Sulfur-FRGAS was produced at the refinery that is the subject of the attest engagement, and whether the
Certified Sulfur-FRGAS was mixed withany Non-Certified Sulfur-FRGAS, NonSulfur-FRGAS, or any Certified SulfurFRGAS produced at a different refinery.

(5)(i) Select a sample from the list of vessels identified in paragraph (h)(3) of this section used to transport certified and Non-Certified Sulfur-FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:

(ii) Obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure of the vessel, and the port of entry and date of arrival of the vessel. Agree the vessel’s departure and arrival locations and dates from the independent third party and United States importer reports to the information contained in the
commercial document.

(6) Obtain separate listings of all tenders of Non-Sulfur-FRGAS, and perform the following:

(i) Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.128(b).

(ii) Obtain a separate listing of the tenders under paragraph (h)(6) of this section where the gasoline is loaded onto a marine vessel. Select a sample from this listing in accordance with the guidelines in § 80.127, and obtain a commercial document of general
circulation that lists vessel arrivals and departures, and that includes the port and date of departure and the ports and dates where the gasoline was off loaded
for the selected vessels. Determine and report as a finding the country where the gasoline was off loaded for each
vessel selected.

(7) In order to complete the requirements of this paragraph (h) an
auditor shall:

(i) Be independent of the foreign refiner;

(ii) Be licensed as a Certified Public
Accountant in the United States and a citizen of the United States, or be approved in advance by EPA based on a demonstration of ability to perform the procedures required in §§ 80.125 through 80.130 and this paragraph (h);
and

(iii) Sign a commitment that contains the provisions specified in paragraph (i) of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.130, § 80.415 and this paragraph (h).

(i) Foreign refiner commitments. Any foreign refiner shall commit to and comply with the provisions contained in this paragraph (i) as a condition to being assigned an individual refinery
sulfur baseline.

(1) Any United States Environmental Protection Agency inspector or auditor will be given full, complete and
immediate access to conduct inspections and audits of the foreign refinery.

(i) Inspections and audits may be either announced in advance by EPA, or
unannounced.

(ii) Access will be provided to any
location where:

(A) Gasoline is produced; (B) Documents related to refinery operations are kept;

(C) Gasoline or blendstock samples are tested or stored; and

(D) Sulfur-FRGAS is stored or transported between the foreign refinery


### 6843 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

and the United States, including storage tanks, vessels and pipelines.

(iii) Inspections and audits may be by EPA employees or contractors to EPA.

(iv) Any documents requested that are related to matters covered by inspections and audits will be provided to an EPA inspector or auditor on request.

(v) Inspections and audits by EPA may include review and copying of any
documents related to:

(A) Refinery baseline establishment, including the volume and sulfur content, and transfers of title or custody, of any gasoline or blendstocks, whether Sulfur-FRGAS or Non-Sulfur-FRGAS, produced at the foreign refinery during the period January 1, 1997 through the date of the refinery baseline petition or through the date of the inspection or audit if a baseline petition has not been approved, and any work papers related to refinery baseline establishment;

(B) The volume and sulfur content of Sulfur-FRGAS;

(C) The proper classification of gasoline as being Sulfur-FRGAS or as not being Sulfur-FRGAS, or as Certified
Sulfur-FRGAS or as Non-Certified Sulfur-FRGAS;

(D) Transfers of title or custody to Sulfur-FRGAS;

(E) Sampling and testing of SulfurFRGAS;

(F) Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section and § 80.415 including work papers; and

(G) Reports prepared for submission to EPA, and any work papers related to such reports.

(vi) Inspections and audits by EPA may include taking samples of gasoline or blendstock, and interviewing employees.

(vii) Any employee of the foreign
refiner will be made available for interview by the EPA inspector or auditor, on request, within a reasonable time period.

(viii) English language translations of any documents will be provided to an EPA inspector or auditor, on request, within 10 working days.

(ix) English language interpreters will be provided to accompany EPA inspectors and auditors, on request.

(2) An agent for service of process
located in the District of Columbia will be named, and service on this agent constitutes service on the foreign refiner or any employee of the foreign refiner for any action by EPA or otherwise by
the United States related to the requirements of this subpart H.

(3) The forum for any civil or criminal
enforcement action related to the provisions of this section for violations of the Clean Air Act or regulations promulgated thereunder shall be governed by the Clean Air Act, including the EPA administrative forum
where allowed under the Clean Air Act.

(4) United States substantive and procedural laws shall apply to any civil or criminal enforcement action against the foreign refiner or any employee of the foreign refiner related to the provisions of this section.

(5) Submitting a petition for an individual refinery sulfur baseline, producing and exporting gasoline under an individual refinery sulfur baseline, and all other actions to comply with the requirements of this subpart H relating
to the establishment and use of an individual refinery sulfur baseline
constitute actions or activities that satisfy the provisions of 28 U.S.C. section 1605(a)(2), but solely with respect to actions instituted against the foreign refiner, its agents and employees in any court or other tribunal in the
United States for conduct that violates the requirements applicable to the foreign refiner under this subpart H, including conduct that violates Title 18
U.S.C. section 1001 and Clean Air Act section 113(c)(2).

(6) The foreign refiner, or its agents or employees, will not seek to detain or to impose civil or criminal remedies against EPA inspectors or auditors, whether EPA employees or EPA contractors, for actions performed within the scope of EPA employment related to the provisions of this section.

(7) The commitment required by this paragraph (i) shall be signed by the owner or president of the foreign refiner
business.

(8) In any case where Sulfur-FRGAS produced at a foreign refinery is stored or transported by another company between the refinery and the vessel that transports the Sulfur-FRGAS to the United States, the foreign refiner shall obtain from each such other company a
commitment that meets the requirements specified in paragraphs (i)(1) through (7) of this section, and
these commitments shall be included in the foreign refiner’s baseline petition.

(j) Sovereign immunity. By submitting a petition for an individual foreign refinery baseline under this section, or by producing and exporting gasoline to
the United States under an individual refinery sulfur baseline under this section, the foreign refiner, its agents and employees, without exception, become subject to the full operation of the administrative and judicial enforcement powers and provisions of
the United States without limitation based on sovereign immunity, with respect to actions instituted against the foreign refiner, its agents and employees in any court or other tribunal in the
United States for conduct that violates the requirements applicable to the foreign refiner under this subpart H, including conduct that violates Title 18
U.S.C. section 1001 and Clean Air Act section 113(c)(2).

(k) Bond posting. Any foreign refiner shall meet the requirements of this paragraph (k) as a condition to being assigned an individual refinery sulfur
baseline.

(l) The foreign refiner shall post a bond of the amount calculated using the following equation:

Bond=G×$ 0.01

where:

Bond=amount of the bond in U. S.
dollars. G=the largest volume of gasoline produced at the foreign refinery and exported to the United States, in gallons, during a single calendar year among the most recent of the following calendar years, up to a maximum of five calendar years: the calendar year immediately preceding the date the baseline petition is submitted, the calendar year the baseline petition is submitted, and each succeeding calendar year. (2) Bonds shall be posted by: (i) Paying the amount of the bond to the Treasurer of the United States;

(ii) Obtaining a bond in the proper amount from a third party surety agent that is payable to satisfy United States administrative or judicial judgments against the foreign refiner, provided EPA agrees in advance as to the third party and the nature of the surety
agreement; or

(iii) An alternative commitment that results in assets of an appropriate liquidity and value being readily available to the United States, provided EPA agrees in advance as to the
alternative commitment.

(3) If the bond amount for a foreign refinery increases, the foreign refiner
shall increase the bond to cover the shortfall within 90 days of the date the bond amount changes. If the bond amount decreases, the foreign refiner may reduce the amount of the bond beginning 90 days after the date the bond amount changes.

(4) Bonds posted under this paragraph (k) shall:

(i) Be used to satisfy any judicial judgment that results from an administrative or judicial enforcement
action for conduct in violation of this subpart H, including where such
conduct violates Title 18 U.S.C. section


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1001 and Clean Air Act section 113(c)(2);

(ii) Be provided by a corporate surety
that is listed in the United States Department of Treasury Circular 570 ‘‘Companies Holding Certificates of Authority as Acceptable Sureties on Federal Bonds and Acceptable Reinsuring Companies’’ (Available from the U.S. Department of the Treasury, Financial Management Service, Surety Bond Branch, 3700 East-West Highway, Room 6A04, Hyattsville, Md. 20782. Also available on the internet at http:/ /www.fms.treas.gov/c570/c570.html);
and

(iii) Include a commitment that the
bond will remain in effect for at least five (5) years following the end of latest averaging period that the foreign refiner produces gasoline pursuant to the requirements of this Subpart H.

(5) On any occasion a foreign refiner bond is used to satisfy any judgment, the foreign refiner shall increase the
bond to cover the amount used within 90 days of the date the bond is used.

(l) [Reserved] (m) English language reports. Any report or other document submitted to EPA by an foreign refiner shall be in English language, or shall include an English language translation.

(n) Prohibitions. (1) No person may
combine Certified Sulfur-FRGAS with any Non-Certified Sulfur-FRGAS or Non-Sulfur-FRGAS, and no person may
combine Certified Sulfur-FRGAS with any Certified Sulfur-FRGAS produced at a different refinery, until the importer has met all the requirements of paragraph (o) of this section, except as provided in paragraph (e) of this

section.

(2) No foreign refiner or other person may cause another person to commit an action prohibited in paragraph (n)(1) of this section, or that otherwise violates the requirements of this section.

(o) United States importer requirements. Any United States importer shall meet the following requirements:

(1) Each batch of imported gasoline shall be classified by the importer asbeing Sulfur-FRGAS or as Non-SulfurFRGAS, and each batch classified as
Sulfur-FRGAS shall be further classified
as Certified Sulfur-FRGAS or as Noncertified Sulfur-FRGAS.

(2) Gasoline shall be classified as
Certified Sulfur-FRGAS or as NonCertified Sulfur-FRGAS according to the designation by the foreign refiner if this designation is supported by product transfer documents prepared by the foreign refiner as required in paragraph (d) of this section, unless the gasoline is
classified as Non-Certified SulfurFRGAS under paragraph (g) of this

section.

(3) For each gasoline batch classified as Sulfur-FRGAS, any United States importer shall perform the following procedures:

(i) In the case of both Certified and Non-Certified Sulfur-FRGAS, have an independent third party:

(A) Determine the volume of gasoline in the vessel;

(B) Use the foreign refiner’s SulfurFRGAS certification to determine the name and EPA-assigned registration number of the foreign refinery that produced the Sulfur-FRGAS;

(C) Determine the name and country of registration of the vessel used to transport the Sulfur-FRGAS to the United States; and

(D) Determine the date and time the vessel arrives at the United States port of entry.

(ii) In the case of Certified SulfurFRGAS, have an independent third party:

(A) Collect a representative sample from each vessel compartment subsequent to the vessel’s arrival at the United States port of entry and prior to off loading any gasoline from the vessel;

(B) Prepare a volume-weighted vessel composite sample from the compartment samples; and

(C) Determine the sulfur value using the methodologies specified in § 80.330, by:

( 1 ) The third party analyzing the sample; or

( 2) The third party observing the importer analyze the sample.

(4) Any importer shall submit reports within thirty days following the date any vessel transporting Sulfur-FRGAS arrives at the United States port of entry:

(i) To the Administrator containing
the information determined under paragraph (o)(3) of this section; and

(ii) To the foreign refiner containing
the information determined under paragraph (o)(3)(ii) of this section.

(5)(i) Any United States importer shall meet the requirements specified in § 80.195 for any imported gasoline that
is not classified as Certified SulfurFRGAS under paragraph (o)(2) of this

section.

(p) Truck imports of Certified SulfurFRGAS produced at a small refinery. (1)Any refiner whose Certified SulfurFRGAS is transported into the United States by truck may petition EPA to use alternative procedures to meet the following requirements:

(i) Certification under paragraph (d)(5) of this section;

(ii) Load port and port of entry sampling and testing under paragraphs (f) and (g) of this section; (iii) Attest under paragraph (h) of this section; and

(iv) Importer testing under paragraph (o)(3) of this section.

(2) These alternative procedures must
ensure Certified Sulfur-FRGAS remainssegregated from Non-Certified SulfurFRGAS and from Non-Sulfur-FRGAS until it is imported into the United States. The petition will be evaluated based on whether it adequately addresses the following:

(i) Provisions for monitoring pipeline shipments, if applicable, from the refinery, that ensure segregation of
Certified Sulfur-FRGAS from that refinery from all other gasoline;

(ii) Contracts with any terminals and/ or pipelines that receive and/or transport Certified Sulfur-FRGAS, that prohibit the commingling of Certified Sulfur-FRGAS with any of the following:

(A) Other Certified Sulfur-FRGAS from other refineries;

(B) All Non-Certified Sulfur-FRGAS;

or (C) All Non-Sulfur-FRGAS;

(iii) Procedures for obtaining and reviewing truck loading records and United States import documents for
Certified Sulfur-FRGAS to ensure that such gasoline is only loaded into trucks making deliveries to the United States;
and

(iv) Attest procedures to be conducted annually by an independent third party that review loading records and import
documents based on volume reconciliation, or other criteria, to
confirm that all Certified Sulfur-FRGAS remains segregated throughout the distribution system and is only loaded into trucks for import into the United

States.

(3) The petition required by this section must be submitted to EPA along with the application for small refiner status and individual refinery sulfur baseline and standards under § 80.240
and this section.

(q) Withdrawal or suspension of a foreign refinery’s baseline. EPA may withdraw or suspend a baseline that has been assigned to a foreign refinery
where:

(1) A foreign refiner fails to meet any requirement of this section;

(2) A foreign government fails to allow EPA inspections as provided in paragraph (i)(1) of this section;

(3) A foreign refiner asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in this subpart H; or

(4) A foreign refiner fails to pay a civil or criminal penalty that is not satisfied using the foreign refiner bond specified in paragraph (k) of this section.


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(r) Early use of a foreign refinery
baseline. (1) A foreign refiner may begin using an individual refinery baseline before EPA has approved the baseline, provided that:

(i) A baseline petition has been submitted as required in paragraph (b) of this section;

(ii) EPA has made a provisional finding that the baseline petition is complete;

(iii) The foreign refiner has made the commitments required in paragraph (i) of this section;

(iv) The persons who will meet the independent third party and independent attest requirements for the foreign refinery have made the commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this section;
and

(v) The foreign refiner has met the bond requirements of paragraph (k) of
this section.

(2) In any case where a foreign refiner uses an individual refinery baseline before final approval under paragraph (r)(1) of this section, and the foreign refinery baseline values that ultimately are approved by EPA are more stringent than the early baseline values used by the foreign refiner, the foreign refiner shall recalculate its compliance, ab initio, using the baseline values approved by EPA, and the foreign refiner shall be liable for any resulting violation of the conventional gasoline requirements.

(s) Additional requirements for petitions, reports and certificates. Any petition for a refinery baseline under § 80.250 or § 80.295, any alternative procedures under paragraph (r) of this section, any report or other submission required by paragraphs (c), (f)(2), or (i) of this section, and any certification under paragraph (d)(3) of this section
shall be:

(1) Submitted in accordance with procedures specified by the Administrator, including use of any forms that may be specified by the Administrator; and

(2) Be signed by the president or owner of the foreign refiner company, or by that person’s immediate designee, and shall contain the following
declaration:

I hereby certify: (1) that I have actual authority to sign on behalf of and to bind [insert name of foreign refiner] with regard to all statements contained herein; (2) that I am
aware that the information contained herein is being certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR. Part 80, subpart H, and that the information is material for determining compliance under these regulations; and (3) that I have read and understand the information being certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof.

I affirm that I have read and understand the provisions of 40 CFR Part 80, subpart H, including 40 CFR 80.410 [insert name of foreign refiner]. Pursuant to Clean Air Act section 113(c) and Title 18, United States Code, section 1001, the penalty for furnishing false, incomplete or misleading information
in this certification or submission is a fine of up to $10,000, and/or imprisonment for up to five years.

Attest Engagements

§ 80.415 What are the attest engagement requirements for gasoline sulfur compliance applicable to refiners and importers?

In addition to the requirements for attest engagements that apply to refiners and importers under §§ 80.125 through 80.130, and § 80.410, the attest engagements for importers and refiners must include the following procedures and requirements each year.

(a) Baseline. (1) Obtain the EPA sulfur baseline approval letter for the refinery to determine the refinery’s applicable
sulfur baseline and baseline volume under §§ 80.250 or 80.295.

(2) If the year being reviewed is 2004 through 2006 (2007 for refineries with small refiner status) and the refinery or importer produced or imported any GPA gasoline under § 80.216 or the refiner has approved status for a small refinery:

(i) Obtain the refinery’s annual sulfur reports for 2000 through 2003; and

(ii) Determine whether the annual average sulfur level for any year credits were generated for 2000 through 2003
was less than the baseline level under paragraph (a)(1) of this section.

(3) If the annual average sulfur content for any year credits were created for 2000 through 2003 was less than the baseline level under paragraph (a)(1) of this section, report as a finding the
lowest annual sulfur level as the new baseline value. For GPA gasoline add 30 ppm to obtain the GPA standard, not to exceed 150 ppm.

(4) If the refinery being reviewed is a small refinery and the annual volume under paragraph (b)(2) of this section is greater than the baseline volume, calculate the applicable standard in accordance with § 80.240(c).

(5) Obtain a written representation from the company representative stating the sulfur value that the company used as its baseline and agree that number to paragraphs (a)(1) through (a)(4) of this section and to the reports to EPA.

(b) EPA reports. (1) Obtain and read a copy of the refinery’s or importer’s annual sulfur reports filed with EPA for the year.

(2) Agree the yearly volume of gasoline reported to EPA in the sulfur reports with the inventory reconciliation analysis under § 80.128.

(3) For the years 2004 through 2006,
calculate the annual volume and average sulfur level for gasoline classified as GPA gasoline under §§ 80.216 and 80.219, and calculate the annual volume and average sulfur level for gasoline not classified as GPA gasoline, and agree these values with the values reported to EPA.

(4) Except as provided in paragraph (b)(3) of this section, calculate the annual average sulfur level for all gasoline and agree that value with the value reported to EPA.

(5) Obtain and read a copy of the refinery’s or importer’s sulfur credit report.

(c) Credit generation before 2004. In the case of a refinery that only generates credits during 2000 through 2003:

(1) Obtain a written representation from the company representative stating the refinery produces gasoline from
crude oil.

(2) Compute and report as a finding the sulfur baseline from paragraph (a) of this section multiplied by 0.9.

(3) Obtain the annual average sulfur level from paragraph (b)(4) of this

section.

(4) If the sulfur value under paragraph (c)(3) of this section is less than the sulfur value under paragraph (c)(2) of this section, compute and report as a finding the difference between the annual average sulfur level and the refinery’s sulfur baseline from paragraph (a) of this section.

(5) Compute and report as a finding
the total number of sulfur credits generated by multiplying the value in paragraph (c)(4) of this section by the volume of gasoline in paragraph (b)(2) of this section, and agree this value with the value reported to EPA.

(d) Credit generation in 2004 and thereafter. The following procedures shall be completed for a refinery or importer that generates credits in 2004
and thereafter:

(1) Obtain the annual average sulfur level for gasoline not classified as GPA from paragraph (b)(3) of this section.

(2) If the sulfur value under paragraph (d)(1) of this section is less than 30 ppm, compute and report as a finding the
difference between the sulfur level under paragraph (d)(1) of this section and 30 ppm.

(3) Compute and report as a finding
the total number of sulfur credits generated by multiplying the value calculated in paragraph (d)(2) of this


### 6846 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

section by the volume of gasoline not classified as GPA in paragraph (b)(3) of this section, and agree this number with the number reported to EPA.

(4) Obtain the annual average sulfur level for gasoline classified as GPA from paragraph (b)(3) of this section.

(5) If the sulfur value under paragraph (d)(4) of this section is less than the applicable level under § 80.310, compute and report as a finding the
difference between the sulfur level under paragraph (d)(4) of this section and the appropriate level in § 80.310 .

(6) Compute and report as a finding
the total number of sulfur credits generated by multiplying the value calculated in paragraph (d)(5) of this section by the volume of gasoline classified as GPA in paragraph (b)(3) of this section, and agree this number with the number reported to EPA.

(7) If the refiner has an approved status as a small refinery, obtain the annual average sulfur level for gasoline from paragraph (b)(4) of this section.

(8) If the sulfur value under paragraph (d)(7) of this section is less than the applicable standard under § 80.240, compute and report as a finding the
difference between the sulfur level under paragraph (d)(7) of this section and the appropriate standard under § 80.240.

(9) Compute and report as a finding
the total number of sulfur credits generated by multiplying the value calculated in paragraph (d)(8) of this section by the volume of gasoline in paragraph (b)(4) of this section, and agree this number with the number reported to EPA.

(e) Credit purchases and sales. The following attest procedures shall be completed for a refinery or importer that
is a transferor or transferee of credits during an averaging period:

(1) Obtain contracts or other
documents for all credits transferred to another refinery or importer during the year being reviewed; compute and report as a finding the number and year of creation of credits represented in these documents as being transferred away; and agree with the report to EPA.

(2) Obtain contracts or other
documents for all credits received during the year being reviewed; compute and report as a finding the number and year of creation of credits represented in these documents as being received; and agree with the report to

EPA.

(f) Credits required for non-GPA gasoline. The following attest procedures shall be completed for refineries and importers in 2005 and thereafter (2004 and thereafter for refineries having standards under § 80.240):

(1) Obtain the annual average sulfur level for gasoline not classified as GPA from paragraph (b)(3) of this section.

(2) If the value in paragraph (f)(1) of this section is greater than 30 ppm (or greater than the small refinery standard), compute and report as a finding the difference between 30 ppm (or the standard under § 80.240) and the value in paragraph (f)(1) of this section.

(3) Compute and report as a finding the total sulfur credits required by multiplying the value in paragraph (f)(2)
of this section times the volume of gasoline not classified as GPA in paragraph (b)(3) of this section, and agree with the report to EPA.

(4) Obtain the refiner’s or importer’s representation as to the portion of the deficit under paragraph (f)(3) of this section that was resolved with credits, the portion that was resolved with allotments in 2005 only or that was
carried forward as a deficit under § 80.205, and agree with the report to EPA (refineries subject to standards under § 80.240 cannot carry deficits forward).

(g) Credits required for GPA gasoline. The following attest procedures shall be completed in 2004 through 2006 for a refinery or importer that produces gasoline subject to the geographic phase-in area standards under § 80.216:

(1) Obtain the annual average sulfur level for the refinery’s or importer’s GPA gasoline from paragraph (b)(3) of
this section.

(2) If the value in paragraph (g)(1) of this section is greater than the refinery’s or importer’s baseline plus 30 ppm under § 80.216, as determined in paragraph (a) of this section or 150 ppm, whichever is less, compute and report as a finding the difference between the annual average sulfur level and the baseline level plus 30 ppm, or 150 ppm,
whichever is less.

(3) Compute and report as a finding
the total sulfur credits and/or allotments required by multiplying the value in paragraph (g)(2) of this section times the volume of GPA gasoline from paragraph (b)(3) of this section.

(4) Obtain the refiner’s or importer’s representation as to the portion of the deficit under paragraph (g)(3) of this section that was resolved with credits, or the portion that was resolved with allotments in 2004 or 2005 only (compliance deficits for GPA gasoline
cannot be carried forward.

(h) Credit expiration. The following attest procedures shall be completed for a refinery or importer that possesses credits during an averaging period: (1) Obtain a list of all credits in the refiner’s or importer’s possession at any time during the year being reviewed, identified by the year of creation of the
credits.

(2) If the year being reviewed is 2006 and thereafter, except in the case of gasoline produced for use in the GPA and gasoline produced by small refiners, determine whether any credits identified in paragraph (h)(1) of this section or Type A sulfur allotments created under paragraph (i) of this
section and converted to credits were created before 2004, and if so, report as a finding this number of expired credits.

(3) If the year being reviewed is 2008 and thereafter, determine whether any credits identified in paragraph (h)(1) of this section or Type B sulfur allotments created under paragraph (i) of this
section and converted to credits were created more than 5 years before the year being reviewed, and if so, report as a finding this number of expired credits (for example, unused credits created during the 2004 averaging period expire at the end of the 2009 averaging period).

(i) Optional credit and allotment generation in 2003. The following requirements apply to any refinery that generates credits and allotments in 2003 under § 80.275(a):

(1) Obtain a written representation from the company representative stating the refinery produces gasoline from
crude oil.

(2) Obtain the refinery baseline value from paragraph (b)(1) of this section, the annual volume from paragraph (b)(2) of this section and the annual average sulfur level from paragraph (b)(4) of this

section.

(3) Based on the annual sulfur level and refinery baseline, determine which equation under § 80.275(a)(2) applies.

(4) Using the applicable equations under § 80.275(a)(2), recalculate the sulfur allotments, by type, and credits and report as a finding.

(j) Credit reconciliation. The following attest procedures shall be completed each year credits were in the refiner’s or importer’s possession at any time during the year:

(1) Obtain the credits remaining or the credit deficit from the previous year from the refiner’s or importer’s report to EPA for the previous year.

(2) Compute and report as a finding the net credits remaining at the conclusion of the year being reviewed by totaling:

(i) Credits remaining from the previous year; plus

(ii) Credits generated under paragraphs (c), (d) and (i) of this section; plus


### 6847 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(iii) Allotments generated under paragraph (i) of this section which are converted to credits; plus

(iv) Credits purchased under paragraph (e) of this section; minus

(v) Credits sold under paragraph (e) of this section; minus

(vi) Credits used under paragraphs (f) and (g) of this section; minus

(vii) Credits expiring under paragraph (h) of this section; minus

(viii) Credit deficit from the previous

year.

(3) Agree the credits remaining or the
credit deficit at the conclusion of the year being reviewed with the report to

EPA.

(4) If the refinery or importer had a credit deficit for both the previous year and the year being reviewed, report this fact as a finding.

(k) Sulfur allotments in 2004 and

2005. The following requirements apply to any refinery or importer that is subject to corporate pool average standards under § 80.195:

(1) Corporate pool average. (i) Obtain the annual average sulfur level for the refiner or importer from the sulfur report filed with EPA for all gasoline subject to corporate pool standards (all gasoline produced and imported, except that if 50% or greater of the gasoline volume was GPA gasoline the refiner or importer is not subject to the corporate pool average).

(ii) Compute and report as a finding the company’s gasoline volume subject to corporate pool standards and average sulfur level for gasoline subject to corporate pool standards, and agree with the values reported to EPA.

(2) Allotment generation. (i) For 2004, if the corporate pool average is less than 120 ppm, compute and report as a finding the number and type of sulfur allotments generated in accordance with the applicable provisions under § 80.275(b).

(ii) For 2005, if the corporate pool average is less than 90 ppm, compute and report as a finding the number and type of sulfur allotments generated in accordance with the applicable provisions under § 80.275(b).

(iii) If the refiner or importer produced and imported 50% or more of its gasoline for GPA use in 2004 or 2005, no allotments can be generated in that

year.

(3) Allotment purchases and sales. (i)
Obtain contracts or other documents for
all allotments transferred to another company during the year being reviewed; compute and report as a finding the number of allotments represented in these documents as being transferred away; and agree with the report to EPA. (ii) Obtain contracts or other
documents for all allotments received during the year being reviewed; compute and report as a finding the number of allotments represented in these documents as being received; and agree with the report to EPA.

(4) Allotments required. (i) For 2004, if the corporate pool average is greater than 120 ppm, compute and report as a finding the number of allotments required by multiplying the amount the corporate pool average is above 120 ppm times the corporate pool volume, and agree with the report to EPA.

(ii) For 2005, if the corporate pool average is greater than 90 ppm, compute and report as a finding the number of allotments required by multiplying the amount the corporate pool average is above 90 ppm times the corporate pool volume, and agree with the report to

EPA.

(iii) Obtain the number of allotments used to meet standards for GPA gasoline determined in paragraph (g) of this

section.

(5) Allotment reconciliation. (i) Compute and report as a finding the net allotments remaining at the conclusion of the year being reviewed by totaling
allotments:

(A) Generated under paragraphs (i)(4) and (k)(2) of this section; plus

(B) Purchased under paragraph (k)(3) of this section; minus

(C) Sold under paragraph (k)(3) of this section; minus

(D) Used under paragraph (k)(4) of this section for demonstrating compliance with the corporate pool

average.

(ii) Report as a finding any allotments generated in 2003 or 2004 that are used to meet the corporate pool standards in 2005 that were not reduced to 50% of their original value.

(iii) If the company’s net allotments remaining are less than zero, report this fact as a finding.

PART 85—CONTROL OF AIR
POLLUTION FROM MOBILE SOURCES

5. The authority citation for part 85
continues to read as follows:

Authority: 42 U.S.C. 7521, 7522, 7524, 7525, 7541, 7542, 7601(a).

6. Section 85.1515 is amended by: a. redesignating the existing paragraph (c) as paragraph (c)(1),

b. adding new paragraphs (c)(2), (c)(3), (c)(5), (c)(6) and (c)(7), and adding and reserving paragraph (c)(4), and

c. revising paragraph (d).

The revisions and additions read as
follows: § 85.1515 Emission standards and test procedures applicable to imported nonconforming motor vehicles and motor vehicle engines.

* * * * *

(c)(1) * * * (2)(i) The provisions of paragraph (c)(1) of this section notwithstanding, nonconforming light-duty vehicles and light light-duty trucks (LDV/LLDTs) modified in model years 2004, 2005 or
2006 must meet the FTP exhaust
emission standards of bin 9 in Tables
S04–1 and S04–2 in 40 CFR 86.1811–04 and the evaporative emission standardsfor light-duty vehicles and light lightduty trucks specified in 40 CFR 86.1811–04(e)(5).

(ii) Nonconforming LDT3s and LDT4s (HLDTs) and medium-duty passenger vehicles (MDPVs) modified in model years 2004 through 2006 must meet the
FTP exhaust emission standards of bin
10 in Tables S04–1 and S04–2 in 40 CFR 86.1811–04 and the applicable evaporative standards specified in 40 CFR 86.1811–04(e)(5). For 2004 model year HLDTs and MDPVs where
modifications commence on the first vehicle of a test group before December 21, 2003, this requirement does not apply to the 2004 model year. ICIs opting to bring all of their 2004 model year HLDTs and MDPVs into compliance with the exhaust emission
standards of bin 10 in Tables S04–1 and S04–2 in 40 CFR 86.1811–04, may use the optional higher NMOG values for their 2004–2006 model year LDT2s and

2004–2008 LDT4s.

(iii) Nonconforming LDT3s and LDT4s (HLDTs) and medium-duty passenger vehicles (MDPVs) modified in model years 2007 and 2008 must meet
the FTP exhaust emission standards of
bin 8 in Tables S04–1 and S04–2 in 40 CFR 86.1811–04 and the applicable evaporative standards specified in 40 CFR 86.1811–04(e)(5).

(iv) Nonconforming LDV/LLDTs modified in model years 2007 and later and nonconfoming HLDTs and MDPVs modified in model years 2009 and later
must meet the FTP exhaust emission
standards of bin 5 in Tables S04–1 and S04–2 of 40 CFR 86.1811–04, and the evaporative standards specified in 40 CFR 86.1811(e)(1) through (e)(4).

(v) ICIs are exempt from the Tier 2 and the interim non-Tier 2 phase-in intermediate percentage requirements for exhaust, evaporative and refueling
emissions described in 40 CFR 86.1811–

04.

(3)(i) As an option to the requirements of paragraph (c)(2) of this section, independent commercial importers may
elect to meet lower bins in Tables S04–
1 and S04–2 of 40 CFR 86.1811–04 than


### 6848 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

specified in paragraph (c)(2) of this
section and bank or sell credits as permitted in 40 CFR 86.1860–04 and 40 CFR 86.1861–04. An ICI may not meet higher bins in Tables S04–1 and S04–2 of 40 CFR 86.1811–04 than specified in paragraph (c)(2) of this section unless it
demonstrates to the Administrator at the
time of certification that it has obtained appropriate and sufficient NO X credits from another manufacturer, or has generated them in a previous model year or in the current model year and
not transferred them to another
manufacturer or used them to address other vehicles as permitted in 40 CFR
86.1860–04 and 40 CFR 86.1861–04.

(ii) Where an ICI desires to obtain a certificate of conformity using a bin higher than specified in paragraph (c)(2) of this section, but does not have
sufficient credits to cover vehicles produced under such certificate, the Administrator may issue such certificate
if the ICI has also obtained a certificate of conformity for vehicles certified using a bin lower than that required under paragraph (c)(2) of this section. The ICI may then produce vehicles to the higher bin only to the extent that it has generated sufficient credits from
vehicles certified to the lower bin during the same model year.

(4) [Reserved] (5) Except for the situation where an ICI desires to bank, sell or use NOX credits as described in paragraph (c)(3) of this section, the requirements of 40 CFR 86.1811–04 related to fleet average

NO X standards and requirements to comply with such standards do not apply to vehicles modified under this subpart.

(6) ICIs using bins higher than those specified in paragraph (c)(2) of this section must monitor their production so that they do not produce more
vehicles certified to the standards of
such bins than their available credits
can cover. ICIs must not have a credit deficit at the end of a model year and are not permitted to use the deficit carryforward provisions provided in 40 CFR 86.1860–04(e).

(7) The Administrator may condition the certificates of conformity issued to ICIs as necessary to ensure that vehicles subject to paragraph (c) of this section comply with the appropriate average

NO X standard for each model year. (d) Except as provided in paragraph (c) of this section, ICI’s must not participate in emission-related programs for emissions averaging, banking and trading, or nonconformance penalties.

* * * * *

PART 86—CONTROL OF EMISSIONS
FROM NEW AND IN-USE HIGHWAY
VEHICLES AND ENGINES

7. The authority citation for part 86
continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.
8. In § 86.1 the table in paragraph (b)(4) is amended by revising the entry for ‘‘California Regulatory Requirements Applicable to the ‘LEV II’ Program’’ in alphabetical order and by revising the entry for ‘‘California Regulatory Requirements Applicable to the
National Low Emission Vehicle Program, October 1996’’, to read as
follows:

§ 86.1 Reference materials.

* * * * *

(b) * * *
(4) * * *

Document No. and name 40 CFR part 86 reference

California Regulatory Requirements Applicable to the ‘‘LEV II’’ Program, including:.

1. California Exhaust Emission Standards and Test Procedures for

2003 and Subsequent Model Zero-Emission Vehicles and 2001and Subsequent Model Hybrid Electric Vehicles, in the Passenger Car, Light-duty Truck and Medium-duty Vehicle Classes. August 5, 1999. 86.1806–01; 86.1811–04; 86.1844–01.

2. California Non-Methane Organic Gas Test Procedures. August

5, 1999. 86.1803–01; 86.1810–01; 86.1811–04.

California Regulatory Requirements Applicable to the National Low

Emission Vehicle Program, October 1996. 86.113–004; 86.612–97; 86.1012–97; 86.1702–99; 86.1708–99; 86.1709–99; 86.1717–99; 86.1735–99; 86.1771–99; 86.1775–99; 86.1776–99; 86.1777–99; Appendix XVI; Appendix XVII.

* * * * *

Subpart A—General Provisions for Emission Regulations for 1977 and Later Model Year New Light-Duty Vehicles, Light-Duty Trucks and Heavy-Duty Engines, and for 1985 and
Later Model Year New GasolineFueled, Natural Gas-Fueled, Liquefied

Petroleum Gas-Fueled and MethanolFueled Heavy-Duty Vehicles

9. Section 86.004–11 is amended by adding paragraph (e) to read as follows:

§ 86.004–11 Emission standards for 2004 and later model year diesel heavy-duty engines and vehicles.

* * * * *

(e) The standards described in this section do not apply to diesel-fueled medium-duty passenger vehicles (MDPVs) that are subject to regulation under subpart S of this part, except as specified in subpart S of this part. The
standards described in this section also do not apply to diesel engines used in such MDPVs, except as specified in the regulations in subpart S of this part. The term ‘‘medium-duty passenger vehicle’’ is defined in § 86.1803.

10. Section 86.099–10 is amended by adding paragraph (e) to read as follows:

§ 86.099–10 Emission standards for 1999 and later model year Otto-cycle heavy-duty engines and vehicles.

* * * * *

(e) The standards described in this section do not apply to Otto-cycle medium-duty passenger vehicles (MDPVs) that are subject to regulation under subpart S of this part, except as specified in subpart S of this part. The
standards described in this section also do not apply to Otto-cycle engines used in such MDPVs, except as specified in subpart S of this part. The term ‘‘medium-duty passenger vehicle’’ is defined in § 86.1803.

10a. The heading of Subpart B is
revised to read as follows:

Subpart B—Emission Regulations for1977 and Later Model Year New Lightduty Vehicles, New Light-duty Trucks and New Medium-Duty Passenger Vehicles; Test Procedures

11. Section 86.113–04 is added to
read as follows:

§ 86.113–04 Fuel specifications.

This section includes text that specifies requirements that differ from § 86.113–94. Where a paragraph in § 86.113–94 is identical and applicable to this section, this will be indicated by specifying the corresponding paragraph


### 6849 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

and the statement ‘‘[Reserved]. For guidance see § 86.113–94.’’.

(a) Gasoline fuel. (1) Gasoline having the following specifications will be used by the Administrator in exhaust and evaporative emission testing of petroleum-fueled Otto-cycle vehicles, except that the Administrator will not use gasoline having a sulfur specification higher than 0.0045 weight percent. Gasoline having the following specification or substantially equivalent specifications approved by the Administrator, must be used by the

manufacturer in exhaust and evaporative testing except that octane specifications do not apply:

Item ASTM test method No. Value

Octane, Research, Min. ......................................................................... D 2699 .......................... ............................................ 93 Sensitivity, Min. ...................................................................................... ........................ ....................................................... 7.5 Lead (organic), max. g/U.S. gal. (g/liter) ............................................... D 3237 ................................ ...................................... 0.050 (0.013) Distillation Range: D 86 ..........................................................................

IBP 1 :deg. F (deg. C) ................................................................ ............................................... ................................ 75–95 (23.9–35) 10 pct. point: deg.F (deg.C) .................................................... ............................................... ................................ 120–135 (48.9– 57.2) 50 pct. point: deg.F. (deg.C) ................................................... ............................................... ................................ 200–230 (93.3– 110) 90 pct. point: deg.F (deg.C) .................................................... ............................................... ................................ 300–325 (148.9– 162.8) EP, max: deg.F (deg.C) ........................................................... .............................................. ................................. 415 (212.8) Sulfur, weight pct. .................................................................................. D 1266 .................... .................................................. 0.0015–0.008 Phosphorous, max. g/U.S. gal (g/liter) ................................................... D 3231 ................................ ...................................... 0.005 (0.0013)

RVP 2,3 ................................................................................................... D 3231 ...................... ................................................ 8.7–9.2 (60.0– 63.4) Hydrocarbon composition: D 1319 ...................................................................... Olefins, max. pct. ..................................................................... ........................................ ....................................... 10 Aromatics, max, pct. ................................................................ ........................................... .................................... 35
Saturates .................................................................................. .................................... ........................................... Remainder

1 For testing at altitudes above 1,219 m (4000 feet), the specified range is 75–105 deg. F (23.9–40.6 deg. C).

2 For testing which is unrelated to evaporative emission control, the specified range is 8.0-9.2 psi (55.2–63.4 kPa).

3 For testing at altitudes above 1,219 m (4000 feet), the specified range is 7.6–8.0 psi (52-55 kPa).

(2) For light-duty vehicles, light-duty trucks and medium-duty passenger vehicles certified for 50 state sale, and
for Tier 2 and interim non-Tier 2
vehicles whose certification is carried over from the NLEV program or carried
across from the California LEV I program, ‘‘California Phase 2’’ gasoline having the specifications listed in the table in this section may be used in exhaust emission testing as an option to the specifications in paragraph (a)(1) of
this section. If a manufacturer elects to utilize this option, the manufacturer must conduct exhaust emission testing with gasoline having the specifications listed in the table in this paragraph (a)(2) and in the case of interim non-Tier
2 LDV/Ts and interim non-Tier 2
MDPVs whose certification is carried over from the NLEV program or carried across from California LEV I program
certification the Administrator must also conduct exhaust emission testing with gasoline having the specifications listed in the table in this paragraph (a)(2) . However, the Administrator may use or require the use of test fuel meeting the specifications in paragraph (a)(1) of this section for certification confirmatory testing, selective enforcement auditing and in-use testing for all other vehicles. All fuel property

test methods for this fuel are contained in Chapter 4 of the California Regulatory Requirements Applicable to the National Low Emission Vehicle Program (October, 1996). These requirements are incorporated by reference (see § 86.1).

The table follows:

Fuel property Limit

Octane, (R+M)/2 (min) .............................................................................. 91 Sensitivity (min) ......................................................................................... 7.5 Lead, g/gal (max) (No lead added) .......................................................... 0–0.01 Distillation range, ° F. 10 pct. point, ............................................................................................. 130–150 50 pct. point, ............................................................................................. 200–210 90 pct. point, ............................................................................................. 290–300 EP, maximum ............................................................................................ 390 Residue, vol% (max) ................................................................................. 2.0 Sulfur, ppm by wt. ..................................................................................... 15–40, except that admin istrator may use and approve for use, lowerranges where such ranges are consistent with current California requirements. Phosphorous, g/gal (max) ......................................................................... 0.005 RVP, psi .................................................................................................... 6.7–7.0 Olefins, vol% ............................................................................................. 4.0–6.0 Total aromatic hydrocarbons (vol%) ......................................................... 22–25 Benzene, vol% .......................................................................................... 0.8–1.0 Multi-substituted alkyl Aromatic hydrocarbons, vol% ............................... 12–14 MTBE, vol % ............................................................................................. 10.8–11.2 Additives: ................................................................................................... See chapter 4 of t he California Regulatory Requirements Applicable to the National Low Emission Vehicle Program (October, 1996). These procedures are incorporated by reference (see § 86.1).


### 6850 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

Fuel property Limit

Copper corrosion ...................................................................................... No. 1. Gum, washed, mg/100 ml (max) .............................................................. 3.0 Oxidation stability, minutes (min) .............................................................. 1000 Specific gravity .......................................................................................... No limit; report to p urchaser required. Heat of combustion ................................................................................... No limit; report to purchaser required. Carbon, wt% ............................................................................................. No limit; report to purchaser required. Hydrogen, wt% .......................................................................................... No limit; report to purchaser required.

(3)(i) Unless otherwise approved by the Administrator, unleaded gasoline representative of commercial gasoline that will be generally available through
retail outlets must be used in service accumulation. For model years 2004 and later, and unless otherwise approved by the Administrator, this gasoline must have a minimum sulfur content of 15 ppm. Unless otherwise approved by the Administrator, where the vehicle is to be used for evaporative emission durability demonstration, such fuel must contain ethanol as required by § 86.1824–01(a)(2)(iii). Leaded gasoline
must not be used in service
accumulation.

(ii) Unless otherwise approved by the Administrator, the octane rating of the gasoline used must be no higher than
1.0 Retail octane number above the lowest octane rating that meets the fuel grade the manufacturer will recommend to the ultimate purchaser for the relevant production vehicles. If the
manufacturer recommends a Retail octane number rather than a fuel grade, then the octane rating of the service accumulation gasoline can be no higher
than 1.0 Retail octane number above the
recommended Retail octane number. The service accumulation gasoline must also have a minimum sensitivity of 7.5 octane numbers, where sensitivity is
defined as the Research octane number
minus the Motor octane number. (iii) The Reid Vapor Pressure of the gasoline used must be characteristic of the motor fuel used during the season in
which the service accumulation takes place.

(4) The specification range of the gasoline to be used under this paragraph (a) must be reported in accordance with §§ 86.094–21(b)(3) and 86.1844–01.

(b) through (g) [Reserved]. For guidance see § 86.113–94.

12. Section 86.129–00 is amended by adding a new paragraph (f)(1)(ii)(C) to
read as follows:

§ 86.129–00 Road load power, test weight, and inertia weight class determination.

* * * * *

(f)* * *
(1)* * *
(ii)* * * (C) Regardless of other requirements in this section relating to the testing of HLDTs, for Tier 2 HLDTs, the test weight basis for FTP and SFTP testing (both US06 and SC03), if applicable, is the vehicle curb weight plus 300 pounds. For MDPVs certified to
standards in bin 11 in Tables S04–1 and 2 in § 86.1811–04, the test weight basis must be adjusted loaded vehicle weight (ALVW) as defined in this part.

* * * * *

12.a. The heading of Subpart C is
revised to read as follows: Subpart C—Emission Regulations for
1994 and Later Model Year GasolineFueled New Light-Duty Vehicles, NewLight-Duty Trucks and New MediumDuty Passenger Vehicles; Cold Temperature Test Procedures

13. Section 86.213–04 is added to
read as follows:

§ 86.213–04 Fuel specifications.

Gasoline having the following specifications will be used by the Administrator except that the Administrator will not use gasoline having a sulfur specification higher than 0.0045 weight percent. Gasoline having the specifications set forth in the table in this section, or substantially equivalent specifications approved by the Administrator, may be used by the manufacturer except that the octane specification does not apply. In lieu of using gasoline having these specifications, the manufacturer may, for certification testing, use gasoline having the specifications specified in § 86.113–04 provided the cold CO
emissions are not decreased. Documentation showing that cold CO
emissions are not decreased must be maintained by the manufacturer and
must be made available to the Administrator upon request. The table listing the cold CO fuel specifications
described in the text in this section
follows:



### TABLE

### —C OLD 

### CO F UEL 

### S PECIFICATIONS

Item ASTM test Cold CO low octane value or

range Cold CO high

octane 1 value or

range

(RON+MON)/2, min ............................................................................................................ D 2 699 87.8± .3 92.3±0.5 Sensitivity, min ............................................................................................................... ..... D 2699 7.5 7.5 Distillation range:.

IBP, deg.F ..................................................................................................................... .. D 86 76–96 76–96 10% point, deg.F. ............................................................................................................ D 86 98–118 105–125 50% point, deg.F. ............................................................................................................ D 86 179–214 195–225 90% point, deg.F. ............................................................................................................ D 86 316–346 316–346 EP, max, deg.F ............................................................................................................... D 86 413 413 Sulfur, wt. % .................................................................................................................. ..... D 3120 0.0015–0.008 0.0015–0.008 Phosphorous, g/U.S gal, max ............................................................................................. D 3231 0 .005 0.005 Lead, g/gal, max ............................................................................................................... .. 0.01 0.01 RVP, psi ....................................................................................................................... ....... D 4953 11.5± .3 11.5± .3 Hydrocarbon composition ................................................................................................... D 131 9

Olefins, vol. pct .............................................................................................................. . 12.5±5.0 10.0±5.0 Aromatics, vol. pct ........................................................................................................... 2 6.4±4.0 32.0±4.0
Saturates ...................................................................................................................... ... Remainder Remainder.

1 Gasoline having these specifications may be used for vehicles which are designed for the use of high-octane premium fuel.


### 6851 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

Subpart R—General Provisions for the Voluntary National Low Emission Vehicle Program for Light-Duty Vehicles and Light-Duty Trucks

14. Section 86.1701–99 is amended by adding paragraph (f) to read as follows:

§ 86.1701–99 General applicability.

* * * * *

(f) The provisions of this subpart are not applicable to 2004 or later model year vehicles, except where specific references to provisions of this subpart are made in conjunction with provisions applicable to such vehicles.

14.a. The title of subpart S is revised
to read as follows:

Subpart S—General Compliance
Provisions for Control of Air Pollution From New and In-use Light-Duty Vehicles, Light-Duty Trucks and Medium Duty Passenger Vehicles

15. Section 86.1801–01 is amended by:

a. revising the first sentence of paragraph (a),

b. adding one sentence to the end of paragraph (c)(1),

c. revising the first sentence of paragraph (e), and

d. adding paragraphs (f), (g) and (h).

These revisions and additions read as
follows:

§ 86.1801–01 Applicability.

(a) Except as otherwise indicated, the provisions of this subpart apply to new 2001 and later model year Otto-cycle and diesel cycle light-duty vehicles, light-duty trucks and medium-dutypassenger vehicles, including multifueled, alternative fueled, hybrid electric, and zero emission vehicles.

***

* * * * *

(c) * * * (1) * * * A 2004 or later model year heavy-duty vehicle optionally certified as a light-duty truck under this provision must comply with all provisions applicable to MDPVs including exhaust and evaporativeemission standards, test procedures, onboard diagnostics, refueling standards, phase-in requirements and fleet average
standards under 40 CFR Part 85 and this
part.

* * * * *

(e) National Low Emission Vehicle Program for light-duty vehicles and light light-duty trucks. A manufacturer may elect to certify 2001–2003 model year light-duty vehicles and light light-duty trucks (LDV/LLDTs) to the provisions of
the National Low Emission Vehicle Program contained in Subpart R of this part. * * *

(f) ‘‘Early’’ Tier 2 LDVs, LDTs and

MDPVs. Any LDV/LLDT which is
certified to Tier 2 FTP exhaust standards prior to the 2004 model year, or any HLDT or MDPV which is
certified to the Tier 2 FTP exhaust standards prior to the 2008 model year, to utilize alternate phase-in schedules and/or for purposes of generating and banking Tier 2 NO X credits, must comply with all the exhaust emission requirements applicable to Tier 2 LDV/ LLDTs or HLDT/ MDPVs, as applicable, under this subpart.

(g) Interim non-Tier 2 LDVs, LDTs and

MDPVs. Model year 2004–2008 LDVs, LDTs and MDPVs, that do not comply
with the Tier 2 FTP exhaust emission requirements (interim non-Tier 2 LDV/
LLDTs and interim non-Tier 2 HLDT/MDPVs) as permitted under the phasein requirements of § 86.1811–04(k) mustcomply with all applicable interim nonTier 2 exhaust emission requirements contained in this subpart, including FTP exhaust emission requirements for all
interim non-Tier 2 LDV/LLDTs and HLDT/MDPVs found at § 86.1811–04(l). Additional emission bins and separate fleet average NO X emission standards and other provisions are provided for interim non-Tier 2 LDV/LLDTs, and
interim non-Tier 2 HLDT/MDPVs.

(h) Applicablity of provisions of this subpart to LDVs, LDTs and MDPVs. Numerous sections in this subpart provide requirements or procedures applicable to a ‘‘vehicle’’ or ‘‘vehicles’’. Unless otherwise specified or otherwise determined by the Administrator, the
term ‘‘vehicle’’ or ‘‘vehicles’’ in those provisions apply equally to LDVs, LDTs
and MDPVs.

16. Section 86.1803–01 is amended by adding the following definitions in alphabetical order to read as follows:

§ 86.1803–01 Definitions.

* * * * *

Bin or emission bin means a set of emission standards applicable to exhaust pollutants measured on the Federal Test Procedure (FTP). A bin is equivalent to a horizontal row of FTP
standards in Tables S04–1 and S04–2 shown in this subpart. Manufacturers are generally free to choose the bin of standards that will apply to a certain test group of vehicles, provided that on a sales weighted average of those bins, all of their vehicles meet a specified fleet average standard for a particular pollutant.

* * * * * CalLEV II or California LEV II refers to California’s second phase of its low emission vehicle (LEV) program. This program was adopted at the hearing of

the California Air Resources Board held on November 5, 1998 and became effective on November 27, 1999.

* * * * *

Fleet average NO X standard means, for light-duty vehicles, light-duty trucks and medium-duty passenger vehicles, a

NO X standard imposed over an

individual manufacturer’s total U.S. sales (or a fraction of total U.S. sales during phase-in years), as ‘U.S. sales’’ is defined in this subpart, of a given model year. Manufacturers determine their compliance with such a standard by averaging, on a sales weighted basis, the

individual NO X standards they choosefor the fleet of light-duty vehicles, lightduty trucks and medium-duty passenger vehicles they sell of that model year.

* * * * *

Interim non-Tier 2 vehicle, interim non-Tier 2 LDV/LLDT, interim non-Tier 2 HLDT/MDPV, or interim vehicle refer to 2004 or later model year light-duty vehicles, light-duty trucks or MDPVs, or a specific combination thereof, not

certified to Tier 2 FTP exhaust emission standards during the Tier 2 phase-in period. Model year 2004 HLDTs belonging to test groups whose model year commences before December 21,
2003, are not interim non-Tier 2 HLDTs

unless their manufacturer chooses to comply with the interim requirements applicable to HLDTs for all of its 2004 model year HLDTs as permitted in this subpart. Similarly 2004 model year heavy-duty vehicles whose model year commences before December 21, 2003,

are not interim non-Tier 2 MDPVs

unless their manufacturer chooses to comply with the interim requirements applicable to MDPVs for all of its 2004 model year MDPVs as permitted in this subpart. The terms interim non-Tier 2 vehicle, interim non-Tier 2 LDV, interim
non-Tier 2 LDT, interim non-Tier 2
HLDT, interim non-Tier 2 MDPV, etc. have the same meaning without the

words ‘‘non-Tier 2’’.

* * * * *

LDV/T means light-duty vehicles and light-duty trucks collectively, without regard to category.

* * * * *

Medium-duty passenger vehicle (MDPV) means any heavy-duty vehicle


### 6852 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(as defined in this subpart) with a gross vehicle weight rating (GVWR) of less than 10,000 pounds that is designed primarily for the transportation of persons. The MDPV definition does not include any vehicle which:

(1) Is an ‘‘incomplete truck’’ as defined in this subpart; or

(2) Has a seating capacity of more than 12 persons; or

(3) Is designed for more than 9 persons in seating rearward of the driver’s seat; or

(4) Is equipped with an open cargo area (for example, a pick-up truck box or bed) of 72.0 inches in interior length or more. A covered box not readily accessible from the passenger compartment will be considered an open cargo area for purposes of this
definition.

* * * * *

Non-methane organic gases (NMOG)means the sum of oxygenated and nonoxygenated hydrocarbons contained in a gas sample as measured in accordance
with the California Non-Methane Organic Gas Test Procedures. These requirements are incorporated by reference (see § 86.1)

* * * * *

Periodically regenerating trap oxidizer system means a trap oxidizer that utilizes, during normal driving conditions, an automated regeneration mode for cleaning the trap, the operation of which can be easily
detected.

* * * * *

Point of first sale means the location where the completed vehicle is first purchased. This term is synonymous with final product purchase location. The point of first sale may be a retail customer, dealer, distributor, fleet operator, broker, secondary manufacturer, or any other entity which purchases a vehicle from a
manufacturer. In cases where the end user purchases the completed vehicle directly from the manufacturer, the end user is the point of first sale.

* * * * *

Round, rounded or rounding means, unless otherwise specified, that numbers will be rounded according to ASTM–E29–93a, which is incorporated by reference in this part pursuant to § 86.1.

* * * * *

Tier 2 HLDT/MDPV means any heavy light-duty truck or medium-duty passenger vehicle, including HEVs and ZEVs, of the 2008 or later model year certified to comply with the Tier 2 FTP
exhaust standards contained in § 86.1811–04 including the 0.07 g/mi fleet average NO X standard. The term Tier 2 HLDT/MDPV also includes any heavy light-duty truck or medium-duty passenger vehicle, of any model year,
which is certified to Tier 2 FTP exhaust standards for purposes of generating or banking early NO X credits for averaging under Tier 2 requirements, or utilizing alternate phase-in schedules, as allowed in this subpart.

Tier 2 LDV/LLDT means any lightduty vehicle or light light-duty truck, including HEVs and ZEVs, of the 2004 or later model year certified to comply
with the Tier 2 FTP exhaust standards contained in § 86.1811–04 including the 0.07 g/mi fleet average NO X standard.
The term Tier 2 LDV/LLDT also includes any light-duty vehicle or light light-duty truck, of any model year,
which is certified to Tier 2 FTP exhaust standards for purposes of generating or banking early NO X credits for averaging under Tier 2 requirements, or utilizing alternate phase-in schedules as allowed in this subpart.

Tier 2 standards means those FTP
exhaust emission standards including the 0.07 g/mi full useful life fleet average NO X standard, applicable tonew light-duty vehicles and light lightduty trucks that begin a phase-in in the 2004 model year, and those exhaust
emission standards including the 0.07 g/ mi full useful life fleet average NO X standard, applicable to heavy light-duty trucks and medium-duty passenger vehicles that begin a phase-in in the 2008 model year. These standards are found in § 86.1811–04 of this subpart.

Tier 2 vehicle means any vehicle certified to comply with the Tier 2 FTP
exhaust standards contained in § 86.1811–04 including the 0.07 g/mi fleet average NO X standard.

* * * * *

U.S. sales means, unless otherwise specified, sales in any state of the United States except for California or a state that has adopted California motor vehicle standards for that model year pursuant to section 177 of the Clean Air Act. This definition applies only to those regulatory requirements addressing Tier 2 and interim non-Tier
2 vehicles.

* * * * *

17. Section 86.1804–01 is amended by adding the following acronyms and abbreviations, in alphabetical order, to
read as follows:

§ 86.1804–01 Acronyms and abbreviations.

* * * * *

HCHO—Formaldehyde. HEV—Hybrid electric vehicle.

* * * * *

HLDT—Heavy light-duty truck. Includes only those trucks over 6000 pounds GVWR (LDT3s and LDT4s). HLDT/MDPV—Heavy light-duty trucks and medium-duty passenger vehicles.

* * * * *

LDV/LLDT—Light-duty vehicles and light light-duty trucks. Includes only those trucks rated at 6000 pounds GVWR or less (LDT1s and LDT2s).

LDV/T—Light-duty vehicles and light-duty trucks. This term is used collectively to include, or to show that a provision applies to, all light-duty vehicles and all categories of light-duty trucks, i.e.

LDT1, LDT2, LDT3 and LDT4.
LEV—Low Emission Vehicle.

* * * * *

MDPV—Medium-duty passenger vehicle.

* * * * *

NLEV—Refers to the National Low Emission Vehicle Program. Regulations governing this program are found at subpart R of this part.

* * * * *

NMOG—Non-methane organic gases.

* * * * *

RAF—Reactivity adjustment factor.

* * * * *

SULEV—Super Ultra Low Emission
Vehicle.

* * * * *

TLEV—Transitional Low Emission
Vehicle.

* * * * *

ULEV—Ultra Low Emission Vehicle.

* * * * *

ZEV—Zero Emission Vehicle.

18. Section 86.1805–04 is added to
read as follows:

§ 86.1805–04 Useful life.

(a) Except as required under paragraph (b) of this section or permitted under paragraphs (d), (e) and (f) of this section, the full useful life for all LDVs, LDT1s and LDT2s is a period of use of 10 years or 120,000 miles,
whichever occurs first. For all HLDTs and MDPVs, full useful life is a period of 11 years or 120,000 miles, whichever occurs first. This full useful life applies to all exhaust, evaporative and refueling emission requirements except for standards which are specified to only be applicable at the time of certification.

(b) Manufacturers may elect to optionally certify a test group to the Tier
2 exhaust emission standards for 150,000 miles to gain additional NOX credits, as permitted in § 86.1860–04(g), or to opt out of intermediate life standards as permitted in § 86.1811– 04(c). In such cases, useful life is a period of use of 15 years or 150,000 miles, whichever occurs first, for all exhaust, evaporative and refueling emission requirements except for cold
CO standards and standards which are applicable only at the time of
certification.

(c) Where intermediate useful life
exhaust emission standards are


### 6853 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

applicable, such standards are applicable for five years or 50,000 miles,
whichever occurs first.

(d) Where cold CO standards are applicable, the useful life requirement for compliance with the cold CO standard only, is 5 years or 50,000 miles, whichever occurs first.

(e) Where LDVs, LDT1s and LDT2s of the 2003 or earlier model years are
certified to Tier 2 exhaust emission standards for purposes of generating early Tier 2 NO X credits, manufacturers may certify those vehicles to full useful lives of 100,000 miles in lieu of the otherwise required 120,000 mile full useful lives, as provided under § 86.1861–04(c)(4).

(f) For interim non-Tier 2 LDV/LLDTs, the useful life requirement for exhaust, evaporative and refueling emissions is 10 years or 100,000 miles, whichever
occurs first.

19. Section 86.1806–01 is amended by:

a. revising paragraph (a); b. adding paragraph (b)(8); c. redesignating the text of paragraph (d) after the paragraph heading as (d)(1);
and

d. adding paragraph (d)(2).
The revisions and additions read as
follows:

§ 86.1806–01 On-board diagnostics.

(a)(1) Except as provided byparagraph (a)(2) of this section, all lightduty vehicles, light-duty trucks and MDPVs must be equipped with an onboard diagnostic (OBD) system capable of monitoring, for each vehicle’s useful life, all emission-related powertrain systems or components. All systems and components required to be monitored by these regulations must be evaluated periodically, but no less frequently than once per Urban Dynamometer Driving Schedule as defined in Appendix I, paragraph (a), of this part, or similar trip as approved by
the Administrator.

(2) Diesel fueled chassis-certified MDPVs and engine-certified diesel engines used in MDPVs, are subject to the requirements of this section only if
the exhaust emission certification of the applicable test group is being carried across from a California configuration to which California OBD–II requirements are applicable.

(b) * * * (8) For Tier 2 and interim non-Tier 2 hybrid electric vehicles (HEVs) only. Unless added to HEVs in compliance with other requirements of this section, or unless otherwise approved by the
Administrator:

(i) The manufacturer must equip each
HEV with a maintenance indicator consisting of a light that must activate automatically by illuminating the first time the minimum performance level is observed for each battery system component. Possible battery system components requiring monitoring are: battery water level, temperature control, pressure control, and other parameters critical for determining battery
condition.

(ii) The manufacturer must equip ‘‘offvehicle charge capable HEVs’’ with a useful life indicator for the battery system consisting of a light that must illuminate the first time the batterysystem is unable to achieve an allelectric operating range (starting from a full state-of-charge) which is at least 75 percent of the range determined for the vehicle in the Urban Driving Schedule portion of the All-Electric Range Test (see the California Exhaust Emission
Standards and Test Procedures for 2003 and Subsequent Model Zero-Emission Vehicles, and 2001 and Subsequent Model Hybrid Electric Vehicles, in the Passenger Car, Light-Duty Truck and Medium-Duty Vehicle Classes. These requirements are incorporated by reference (see § 86.1).

(iii) The manufacturer must equip each HEV with a separate odometer or other device subject to the approval of the Administrator that can accurately measure the mileage accumulation on the engines used in these vehicles.

* * * * *

(d) MIL illumination. (1) * * * (2)(i) For interim non-Tier 2 and Tier 2 LDV/LLDTs and HLDT/MDPVs, vehicles produced through the 2007 model year, upon a manufacturer’s written request, EPA will consider allowing the use of an on-board diagnostic system during the certification process, that functions properly on low-sulfur gasoline, but indicates sulfur-induced passes when exposed to high sulfur gasoline.

(ii) For interim non-Tier 2 and Tier 2 LDV/LLDTs and HLDT/MDPVs, if vehicles produced through the 2007 model year exhibit illuminations of the emission control diagnostic system malfunction indicator light due to high sulfur gasoline, EPA will consider, upon a manufacturer’s written request, allowing modifications to such vehicles on a case-by-case basis so as to
eliminate the sulfur induced
illumination.

* * * * *

20. Section 86.1807–01 is amended by revising paragraph (a)(3)(vi) to read as
follows:

§ 86.1807–01 Vehicle labeling.

(a) * * * (3) * * * (vi) The exhaust emission standards to which the test group is certified, and for test groups having different in-use standards, the corresponding exhaust emission standards that the test group
must meet in use. In lieu of this requirement, manufacturers may use the standardized test group name designated by EPA;

* * * * *

21. Section 86.1809–01 is amended by adding paragraph (e) to read as follows:

§ 86.1809–01 Prohibition of defeat devices.

* * * * *

(e) For each test group of Tier 2 LDV/
LLDTs and HLDT/MDPVs and interim
non-Tier 2 LDV/LLDTs and HLDT/ MDPVs the manufacturer must submit, with the Part II certification application, an engineering evaluation demonstrating to the satisfaction of the Administrator that a discontinuity in emissions of non-methane organic gases, carbon monoxide, oxides of nitrogen and formaldehyde measured on the Federal Test Procedure (subpart B of this part) does not occur in the temperature range of 20 to 86 degrees F. For diesel vehicles, the engineering evaluation must also include particulate

emissions.

22. Section 86.1810–01 is amended by:

a. adding two new sentences to the end of the introductory text;

b. adding one new sentence to the end of paragraph (f);

c. adding a new sentence to the end of paragraph (i)(6); and

d. adding new paragraphs (i)(13), (i)(14), (o) and (p).

The additions read as follows:

§ 86.1810–01 General standards; increase in emissions; unsafe conditions; waivers.

* * * For Tier 2 and interim non-Tier 2 vehicles, this section also applies to hybrid electric vehicles and zero
emission vehicles. Unless otherwise specified, requirements and provisions of this subpart applicable to methanol fueled vehicles are also applicable to
Tier 2 and interim non-Tier 2 ethanol
fueled vehicles.

* * * * *

(f) * * * Interim non-Tier 2 LDV/Ts may be certified to applicable Tier 1 exhaust emission standards at high altitude as set forth in §§ 86.1811–01,

86.1812–01, 86.1813–01, 86.1814–02 and 86.1815–02. Requirements to meet emission standards at high altitude are optional for interim non-Tier 2 MDPVs.

* * * * *

(i) * * *(6) * * * For Tier 2 and interim nonTier 2 vehicles, this provision does not


### 6854 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

apply to enrichment that occurs upon cold start, warm-up conditions andrapid-throttle motion conditions (‘‘tipin’’ or ‘‘tip-out’’ conditions).

* * * * *

(13) A/C-on specific calibrations. (i)
For Tier 2 and interim non-Tier 2 vehicles, A/C-on specific calibrations (e.g. air to fuel ratio, spark timing, and exhaust gas recirculation), may be used
which differ from A/C-off calibrations for given engine operating conditions (e.g., engine speed, manifold pressure, coolant temperature, air charge temperature, and any other parameters).

(ii) Such calibrations must not unnecessarily reduce the NMHC+NO X emission control effectiveness during A/ C-on operation when the vehicle is operated under conditions which may reasonably be expected to be encountered during normal operation
and use.

(iii) If reductions in control system

NMHC+NO X effectiveness do occur as a result of such calibrations, the manufacturer must, in the Application for Certification, specify the
circumstances under which such reductions do occur, and the reason for the use of such calibrations resulting in such reductions in control system
effectiveness.

(iv) A/C-on specific ‘‘open-loop’’ or
‘‘commanded enrichment’’ air-fuel enrichment strategies (as defined below), which differ from A/C-off ‘‘open-loop’’ or ‘‘commanded
enrichment’’ air-fuel enrichment strategies, may not be used, with the following exceptions: Cold-start and warm-up conditions, or, subject to Administrator approval, conditions requiring the protection of the vehicle, occupants, engine, or emission control hardware. Other than these exceptions, such strategies which are invoked based on manifold pressure, engine speed, throttle position, or other engine parameters must use the same engine parameter criteria for the invoking of this air-fuel enrichment strategy and the same degree of enrichment regardless ofwhether the A/C is on or off. ‘‘Openloop’’ or ‘‘commanded’’ air-fuel enrichment strategy is defined as
enrichment of the air to fuel ratio beyond stoichiometry for the purposes of increasing engine power output and the protection of engine or emissionscontrol hardware. However, ‘‘closedloop biasing,’’ defined as small changes in the air-fuel ratio for the purposes of optimizing vehicle emissions or driveability, must not be considered an ‘‘open-loop’’ or ‘‘commanded’’ air-fuel enrichment strategy. In addition, ‘‘transient’’ air-fuel enrichment strategy (or ‘‘tip-in’’ and ‘‘tip-out’’ enrichment),defined as the temporary use of an airfuel ratio rich of stoichiometry at the beginning or duration of rapid throttle motion, must not be considered an ‘‘open-loop’’ or ‘‘commanded’’ air-fuel enrichment strategy.

(14) ‘‘ Lean-on-cruise’’ calibration strategies. (i) For Tier 2 and interim non-Tier 2 vehicles, the manufacturer must state in the Application forCertification whether any ‘‘lean-oncruise’’ strategies are incorporated into the vehicle design. A ‘‘lean-on-cruise’’ air-fuel calibration strategy is defined as the use of an air-fuel ratio significantlygreater than stoichiometry, during nondeceleration conditions at speeds above 40 mph. ‘‘Lean-on-cruise’’ air-fuel calibration strategies must not be employed during vehicle operation in normal driving conditions, including A/ C usage, unless at least one of the following conditions is met:

(A) Such strategies are substantially employed during the FTP or SFTP;

(B) Such strategies are demonstrated not to significantly reduce vehicle

NMHC+NO X emission control effectiveness over the operating conditions in which they are employed;

or (C) Such strategies are demonstrated to be necessary to protect the vehicle occupants, engine, or emission control
hardware.

(ii) If the manufacturer proposes to
use a ‘‘lean-on-cruise’’ calibration strategy, the manufacturer must specify
the circumstances under which such a calibration would be used, and the reason or reasons for the proposed use
of such a calibration.

* * * * *

(o) Unless otherwise approved by the Administrator, manufacturers must

measure NMOG emissions in
accordance with the California NonMethane Organic Gas Test Procedures. These procedures are incorporated by reference (see § 86.1).

(p) For gasoline and diesel-fueled Tier 2 and interim non-Tier 2 vehicles,manufacturers may measure nonmethane hydrocarbons (NMHC) in lieu of NMOG. Manufacturers must multiply NMHC measurements from gasoline vehicles by an adjustment factor of 1.04 before comparing with the NMOG standard to determine compliance with that standard. Manufacturers may use other factors to adjust NMHC results to more properly represent NMOG results. Such factors must be based upon comparative testing of NMOG and NMHC emissions and be approved in advance by the Administrator. 23. Section 86.1811–01 is amended by adding a sentence to the end of the introductory text to read as follows:

§ 86.1811–01 Emission standards for lightduty vehicles.

* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811–04.

* * * * *

24. Section 86.1811–04 is added to
read as follows:

§ 86.1811–04 Emission standards for lightduty vehicles, light-duty trucks and medium-duty passenger vehicles.

(a) Applicability. (1) This section contains regulations implementing emission standards for all LDVs, LDTs and MDPVs. This section applies to 2004 and later model year LDVs, LDTs and MDPVs fueled by gasoline, diesel, methanol, ethanol, natural gas and liquefied petroleum gas fuels, except as noted. Additionally, this section contains provisions applicable to hybrid electric vehicles (HEVs) and zero emission vehicles (ZEVs). Multi-fueled vehicles must comply with all requirements established for each
consumed fuel.

(2) This section also applies to LDVs, LDTs and MDPVs of model years prior to 2004, when manufacturers certify
such vehicles to Tier 2 exhaust emissionrequirements to utilize alternate phasein schedules, as allowed under paragraph (k)(6) of this section, and/or to earn early NO X credits for use in complying with the Tier 2 fleet average

NO X standard which takes effect in the 2004 model year for LDV/LLDTs and
2008 for HLDT/MDPVs.

(3) Except where otherwise specified, this section applies instead of §§ 86.1811–01, 86.1812–01, 86.1813–01,

86.1814–01, 86.1814–02, 86.1815–01, and 86.1815–02.

(4) Except where otherwise specified, the provisions of this section apply equally to LDVs and all categories of LDTs, and to all MDPVs. Numerous provisions are applicable equally to HLDTs and MDPVs, as reflected by the
term HLDT/MDPV. Numerous provisions apply equally to LDVs and LLDTs as reflected by the term LDV/

LLDT.

(5) The exhaust emission standards and evaporative emission standards of this section apply equally to certification and in-use LDVs, LDTs and MDPVs, unless otherwise specified.

(b) Test weight. (1) Except as required in paragraphs (b)(2) and (b)(4) of this section, or permitted under paragraph (b)(3) of this section, emission testing of all LDVs, LDTs and MDPVs to


### 6855 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

determine compliance with any exhaust or evaporative emission standard set
forth in this Part must be on a loaded vehicle weight (LVW) basis, as that term is defined in this subpart.

(2) Interim non-Tier 2 HLDTs tested to Tier 1 SFTP standards, must be tested on an adjusted loaded vehicle weight (ALVW) basis, as that term is defined in this subpart, during the SC03 element of
the SFTP.

(3) Except as required in paragraphs (b)(2) and (b)(4) of this section, interim non-Tier 2 HLDT/MDPVs may be tested
on an ALVW basis or an LVW basis to demonstrate compliance with any exhaust or evaporative emission
standard set forth in this Part.

(4) MDPVs certified to bin 11
standards from Tables S04–1 and –2
must be tested on an ALVW basis to demonstrate compliance with any
exhaust emission standard set forth in this part.

(c) Tier 2 FTP exhaust emission
standards. Exhaust emissions from Tier
2 vehicles must not exceed the
standards in Table S04–1 of this section
at full useful life when tested over the Federal Test Procedure (FTP) described in subpart B of this part. Exhaust
emissions from Tier 2 vehicles must not
exceed the standards in Table S04–2 of this section at intermediate useful life, if applicable, when tested over the FTP.

(1) For a given test group a manufacturer desires to certify to operate only on one fuel, the
manufacturer must select a set of standards from the same bin (line or row) in Table S04–1 of this section for non-methane organic gases (NMOG), carbon monoxide (CO), oxides of nitrogen (NO X), formaldehyde (HCHO) and particulate matter (PM). The manufacturer must certify the test group to meet those standards, subject to all the applicable provisions of this subpart. The manufacturer must also certify the test group to meet the intermediate useful life standards (if any) in Table S04–2 of this section having the same EPA bin reference
number as the chosen full useful life
standards.

(2) For a given test group of flexiblefueled, bi-fuel or dual fuel vehicles when operated on the alcohol or gaseous fuel they are designed to use,
manufacturers must select a bin of
standards from Table S04–1 of this section and the corresponding bin in Table S04–2, if any. When these flexible-fueled, bi-fuel or dual fuel vehicles are certified to operate on gasoline or diesel fuel, the manufacturer may choose to comply with the next numerically higher applicable NMOG standard, if any, above the bin which
contains the standards selected for certification on the gaseous or alcohol
fuel.

(3)(i) For a given test group of flexiblefueled, bi-fuel or dual fuel vehicles certified to bin 10 in Table S04–1, when operated on the alcohol or gaseous fuel they are designed to use, manufacturers may choose to comply with a NMOG
standard of 0.230 for LDV/LLDTs or 0.280 g/mi for HLDT/MDPVs at full useful life and corresponding intermediate life standards of 0.160 g/mi and 0.195 g/mi, respectively.

(ii) For a given test group of flexiblefueled, bi-fuel or dual fuel vehicles certified to bin 8 in Table S04–1, when operated on the alcohol or gaseous fuel they are designed to use, manufacturers may choose to comply with a NMOG standard of 0.156 g/mi for LDV/LLDTs
and 0.180 for HLDT/MDPVs at full useful life and corresponding intermediate life standards of 0.125 g/mi and 0.140 g/mi, respectively.

(4)(i) For bins where intermediate life standards are applicable, a manufacturer may elect not to comply with such standards. Except as permitted in paragraph (c)(4)(iv) of this section, the manufacturer must certify such vehicles to a useful life of 15 years or 150,000 miles, whichever occurs first, for LDV/
LLDTs and HLDT/MDPVs.

(ii) A manufacturer electing not to comply with intermediate life standards, as permitted in paragraph (c)(4)(i) of this section, may not generate
additional NO X credits as described under § 86.1860–04 (g), except as permitted in paragraph (c)(4)(iii) of this

section.

(iii) For bins where intermediate life standards are not applicable, or are specified to be optional by paragraph (c)(4)(iv) of this section, a manufacturer may generate additional NO X credits subject to the provisions in § 86.1860– 04 (g).

(iv) For diesel vehicles certified to bin 10, intermediate life standards are optional regardless of whether the manufacturer certifies the test group to a full useful life of 120,000 miles or 150,000 miles.

(5) In a given model year, an individual vehicle may not be included in both the Tier 2 program and an interim program.

(6) Tables S04–1 and S04–2 follow:



### TABLE 

### S04–1.—T IER 

### 2 AND 

### I NTERIM 

### N ON 

### -T IER 

### 2 F ULL 

### U SEFUL 

### L IFE 

### E XHAUST 

### M ASS 

### E MISSION 

### STANDARDS

[Grams per mile]

Bin No. NOX NMOG CO HCHO PM Notes

11 ................................................................................. 0.9 0.280 7.3 0.032 0.12 a, c 10 ................................................................................. 0.6 0.156/0.230 4.2/6.4 0.018/0.027 0.08 a, b , d 9 ................................................................................... 0.3 0.090/0.180 4.2 0.018 0.06 a, b , e 8 ................................................................................... 0.20 0.125/0.156 4.2 0.018 0.02 b, f 7 ................................................................................... 0.15 0.090 4.2 0.018 0.02

6 ................................................................................... 0.10 0.090 4.2 0.018 0.01

5 ................................................................................... 0.07 0.090 4.2 0.018 0.01

4 ................................................................................... 0.04 0.070 2.1 0.011 0.01

3 ................................................................................... 0.03 0.055 2.1 0.011 0.01

2 ................................................................................... 0.02 0.010 2.1 0.004 0.01

1 ................................................................................... 0.00 0.000 0.0 0.000 0.00

Notes:

a This bin and its corresponding intermediate life bin are deleted at end of 2006 model year (end of 2008 model year for HLDTs an d MDPVs).

b Higher NMOG, CO and HCHO values apply for HLDTs and MDPVs only.

c This bin is only for MDPVs.

d Optional NMOG standard of 0.280 g/mi applies for qualifying LDT4s and qualifying MDPVs only.

e Optional NMOG standard of 0.130 g/mi applies for qualifying LDT2s only.

f Higher NMOG standard deleted at end of 2008 model year.


### 6856 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

TABLE 

### S04–2.—T IER 

### 2 AND 

### I NTERIM 

### N ON 

### -T IER 

### 2 I NTERMEDIATE 

### U SEFUL 

### L IFE 

### (50,000 M ILE 

### ) E XHAUST 

### M ASS 

### E MISSION 

### STANDARDS

[grams per mile]

Bin No. NOX NMOG CO HCHO PM Notes

11 ................................................................................. 0.6 0.195 5.0 0.022 acfh
10 ................................................................................. 0.4 0.125/0.160 3.4/4.4 0.015/0.018 ............

........ abdfgh
9 ................................................................................... 0.2 0.075/0.140 3.4 0.015 .................... abcfh
8 ................................................................................... 0.14 0.100/0.125 3.4 0.015 .................... bfhi

7 ................................................................................... 0.11 0.075 3.4 0.015 .................... f h

6 ................................................................................... 0.08 0.075 3.4 0.015 .................... f h

5 ................................................................................... 0.05 0.075 3.4 0.015 .................... f h

Notes:

a This bin deleted at end of 2006 model year (end of 2008 model year for HLDTs and MDPVs ).

b Higher NMOG, CO and HCHO values apply for HLDTs and MDPVs only.

c This bin is only for MDPVs.

d Optional NMOG standard of 0.195 g/mi applies for qualifying LDT4s and qualifying MDPVs only.

e Optional NMOG standard of 0.100 g/mi applies for qualifying LDT2s only.

f The full useful life PM standards from Table S04–1 also apply at intermediate useful life.

g Intermediate life standards of this bin are optional for diesels.

h Intermediate life standards are optional for vehicles certified to a useful life of 150,000 miles.

i Higher NMOG standard deleted at end of 2008 model year.

(d) Fleet average NO X Standards. (1)(i) For a given individual model year’s sales of Tier 2 vehicles, including model years during the phase-in years of the Tier 2 standards, manufacturers must comply with a fleet average oxides of nitrogen (NO X) standard of 0.07 grams per mile. The manufacturer must calculate its fleet average NO X emission level(s) as described in § 86.1860–04. Up through and including model year 2008, manufacturers must calculate separate fleet average NO X emission
levels for LDV/LLDTs and for HLDT/ MDPVs as described in § 86.1860–04.

(ii) During a phase-in year, the manufacturer must comply with the 0.07 g/mi fleet average standard for the required phase-in percentage for that year as specified in paragraph (k)(1) ofthis section, or for the alternate phasein percentage as permitted under paragraph (k)(6) of this section.

(2) For Early Tier 2 LDV/LLDTs. For model years prior to 2004, where the manufacturer desires to bank early Tier

2 NO X credits as permitted under § 86.1861(c), the manufacturer must comply with a fleet average standard of 0.07 grams per mile for its Tier 2 LDV/
LLDTs. Manufacturers must determine compliance with the NO X fleet average standard according to regulations in § 86.1860–04 of this subpart.

(3) For Early Tier 2 HLDT/MDPVs. For model years prior to 2008, where the manufacturer desires to bank early Tier

2 NO X credits as permitted under § 86.1861(c), the manufacturer must comply with a fleet average standard of 0.07 grams per mile for its Tier 2 HLDT/
MDPVs. Manufacturers must determine compliance with the NO X fleet average standard according to regulations in § 86.1860–04. (e) Evaporative emission standards. Consistent with the phase-in requirements in paragraph (k) of this section, evaporative emissions from gasoline-fueled, natural gas-fueled,liquefied petroleum gas-fueled, ethanolfueled and methanol-fueled vehicles
must not exceed the standards in this paragraph. The standards apply equally to certification and in-use vehicles, except that the spitback standard applies only to newly assembled
vehicles.

(1) Diurnal-plus-hot soak evaporative hydrocarbon standards. Hydrocarbons for LDV/LLDTs, HLDTs and MDPVs must not exceed the diurnal plus hot
soak standards shown in Table S04–3 for the full three diurnal test sequence and for the supplemental two diurnal test sequence. Table S04–3 follows:



### TABLE 

### S04–3.—L IGHT

### -D UTY 

### D IURNAL 

### P LUS 

### H OT 

### S OAK 

### E VAPORATIVE 

### E MISSION 

### STANDARDS

[grams per test]

Vehicle category 3 day diurnal+hot soak Supplemental 2

day diurnal+hot soak

LDV/LLDTs ......... 0.95 1.2

HLDTs ................ 1.2 1.5
MDPVs ............... 1.4 1.75

(2) Running loss standard. Hydrocarbons for LDVs, LDTs and MDPVs measured on the running loss test must not exceed 0.05 grams per
mile.

(3) Refueling emission standards. Refueling emissions must not exceed the following standards:

(i) For gasoline-fueled, diesel-fueled and methanol-fueled LDVs, LDTs and MDPVs: 0.20 grams hydrocarbon per gallon (0.053 grams per liter) of fuel dispensed.

(ii) For liquefied petroleum gas-fueled LDV, LDTs and MDPVs: 0.15 grams hydrocarbon per gallon (0.04 grams per liter) of fuel dispensed.

(iii) Refueling standards for HLDTs are subject to the phase-in requirements found in § 86.1810–01(k). MDPVs must also comply with the phase-in requirement in § 86.1810–01(k) and must be grouped with HLDTs to determine phase-in compliance.

(4) Spitback standards. For gasoline
and methanol fueled LDV/Ts and MDPVs, hydrocarbons measured on the fuel dispensing spitback test must not exceed 1.0 grams hydrocarbon (carbon if methanol-fueled) per test.

(5) Evaporative emission requirements for interim vehicles. (i) LDV/Ts not certified to meet the evaporative emission standards in this paragraph (e) as permitted under the phase-in schedule of paragraph (k) of this section, must meet applicable evaporative emission standards in §§ 86.1811–01,

86.1812–01, 86.1813–01, 86.1814–02 or 86.1815–02 except that all LDV/Ts must meet the refueling emission standards in paragraph (e)(3) of this section.

(ii) MDPVs not certified to meet the evaporative emission standards in this paragraph (e) as permitted under the phase-in schedule of paragraph (k) of this section, must meet applicable evaporative emission standards for heavy-duty vehicles in § 86.099–10.

(6) In cases where applicable
California emission standards are as stringent or more stringent than applicable standards specified under this paragraph (e), the Administrator may accept data indicating compliance
with California standards to


### 6857 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

demonstrate compliance for certification purposes with the standards required under this paragraph (e). The Administrator may require manufacturers to provide comparative test data to show that a vehicle meeting

California standards under California test conditions and procedures will also meet the standards under this paragraph (e) when tested under test conditions and procedures in this Part 86.

(f) Supplemental exhaust emission standards for LDV/Ts. (1) Supplemental
exhaust emission standards are applicable to gasoline and diesel-fueled LDV/Ts but are not applicable to MDPVs, alternative fueled LDV/Ts, or flexible fueled LDV/Ts when operated on a fuel other than gasoline or diesel. Except as otherwise specified in this paragraph (f), manufacturers must comply with 4000 mile and full useful
life SFTP standards as determined in this paragraph (f). The 4000 mile SFTP
standards must be taken from Table
S04–4 and the full life SFTP standards must be calculated using the formula in paragraph (f)(2) of this section. Table
S04–4 follows:



### TABLE 

### S04–4.—4000 M ILE 

### SFTP STANDARDS FOR 

### T IER 

### 2 AND 

### I NTERIM 

### N ON 

### -T IER 

### 2 LDVS AND 

### LDTS

US06 SC03

NMHC+NOX (g/mi) CO (g/mi) NMHC+NOX (g/mi) CO (g/mi)

LDV/LDT1 ..................................................................................................................... 0. 14 8.0 0.20 2.7

LDT2 ........................................................................................................................... .. 0.25 10.5 0.27 3.5

LDT3 ........................................................................................................................... .. 0.4 10.5 0.31 3.5

LDT4 ........................................................................................................................... .. 0.6 11.8 0.44 4.0

(2)(i) Manufacturers must calculate their applicable full useful life SFTP

standards for NMHC+NO X , PM and for CO, if using the weighted CO standard. If not using the weighted CO standard, manufacturers may use the full useful

life standalone Tier 1 standards for

US06 and SC03. To calculate the applicable full useful life weighted

NMHC+NO X , PM and CO standards, manufacturers must use the following

formula and values from Table S04–1 in paragraph (c) of this section and values from Tables S04–5 and S04–6 which
follow:

SFTP Standard = SFTP Standard 1 ¥

[0.35 x (FTP Standard 1—Current FTP Standard)]

Where: SFTP Standard = Applicable full life

weighted SFTP standard for

NMHC+NO X , PM or CO. This
standard must be rounded to two decimal places. SFTP Standard 1 = Applicable full life

Tier 1 SFTP standard for NMHC+NOX or CO from Table S04–5. For PM only, use FTP Standard 1 for SFTP

Standard 1

. FTP Standard 1 = Applicable full life

Tier 1 FTP standard from Table S04– 6 in this paragraph (f). For the Tier 1

NMHC+NO X standard, add the applicable NMHC and NOx standards.
Current FTP Standard = Applicable full

life FTP standard from Table S04–1 in paragraph (c) of this section. For the

current NMHC+NO X standard, add

the NMOG and NO X standards from the applicable bin.



### TABLE 

### S04–5.—T IER 

### 1 F ULL 

### U SEFUL 

### L IFE 

### SFTP STANDARDS

Vehicle category NMHC + NOX (weighted

g/mi) a, c CO (g/mi) b, c

US06 SC03 Weighted

LDV/LDT1 ........................................................................................................ 0.91 (0.65) 11.1 (9.0) 3.7 (3.0) 4.2 (3.4) LDT2 ................................................................................................................ 1.37 (1.02) 14.6 (11.6) 4.9 (3.9) 5.5 (4.4)

LDT3 ................................................................................................................ 1.44 16.9 5.6 6.4

LDT4 ................................................................................................................ 2.09 19.3 6.4 7.3

a Weighting for NMHC+NOX and optional weighting for CO is 0.35x(FTP) +0.28x(US06)+0.37x(SC03).

b CO standards are stand alone for US06 and SC03 with option for a weighted standard.

c Intermediate life standards are shown in parentheses for diesel LDV/LLDTs opting to calculate intermediate life SFTP standards in lieu of 4,000 mile SFTP standards as permitted under paragraph (f)(6) of this section.



### TABLE 

### S04–6.—T IER 

### 1 F ULL 

### U SEFUL 

### L IFE 

### FTP STANDARDS 

### ( G

### /MI 

### )

Vehicle category NMHC a NOXa CO a PM

LDV/LDT1 ........................................................................................................ 0.31 (0.25) 0.6 (0.4) 4.2 (3.4) 0.10 LDT2 ................................................................................................................ 0.40 (0.32) 0.97(0.7) 5.5 (4.4) 0.10

LDT3 ................................................................................................................ 0.46 0.98 6.4 0.10

LDT4 ................................................................................................................ 0.56 1.53 7.3 0.12

a Intermediate life standards are shown in parentheses for diesel LDV/LLDTs opting to calculate intermediate life SFTP standards in lieu of 4,000 mile SFTP standards as permitted under paragraph (f)(6)of this section.

(ii)(A) Manufacturers must determine compliance with NMHC+NO X , CO and PM weighted SFTP standards calculated in paragraph (f)(2)(i) of this section by weighting their emission results as
follows:

0.35 ×(FTP)+0.28×(US06)+0.37×(SC03).

(B) The results of the calculation in paragraph (f)(2)(ii)(A) of this section must be rounded to one more decimal place than the applicable standard calculated in paragraph (f)(2)(i) of this section and then compared with that

standard.


### 6858 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(3) For interim non-Tier 2 gasoline,
diesel and flexible-fueled LDT3s and LDT4s, manufacturers may, alternatively, meet the gasoline-fueled
vehicle SFTP standards found in §§ 86.1814–02 and 86.1815–02, respectively.

(4) Interim non-Tier 2 gasoline, diesel
and flexible-fueled LDV/LLDTs certified
to bin 10 FTP exhaust emission
standards from Table S04–1 in paragraph (c) of this section may meet the gasoline Tier 1 SFTP requirements found at § 86.1811–01(b).

(5) SFTP standards for PM are not applicable to interim non-Tier 2 LDV/ Ts. For Tier 2 LDV/Ts, the 4000 mile PM standard is equal to the full life PM standard calculated under paragraph (f)(2) of this section. The requirements of this paragraph (f)(5) also apply to Tier 2 flexible fuel vehicles when operated on gasoline or diesel fuel. (See regulations in § 86.1829-01(b)(1)(iii)(B) regarding data submittal for PM results for gasoline vehicles.)

(6)(i) In lieu of complying with 4000
mile SFTP standards described in this paragraph, diesel LDV/LLDTs through model year 2006, may comply instead
with intermediate life SFTP standards
derived from Tier 1 intermediate life SFTP standards for gasoline vehicles.

(ii) To calculate intermediate life SFTP standards, substitute intermediate
life Tier 1 FTP and SFTP values from
Tables S04–5 and S04–6 in this paragraph (f), as appropriate, for the full life values in the equation in paragraph (f)(2)(i) of this section. Substitute the applicable intermediate life standards
for the full life current FTP standard. If there is no applicable intermediate life
standard use the full life current FTP
standard.

(iii) A manufacturer of diesel LDV/ LLDTs must declare which option it will use (4,000 mile or intermediate life standards) in Part I of its certification application.

(g) Cold temperature exhaust
emission standards. These standards are applicable only to gasoline fueled LDV/ Ts and MDPVs. For cold temperature exhaust emission standards, a useful life of 50,000 miles applies.

(1) For LDVs and LDT1s, the standard is 10.0 grams per mile CO.

(2) For LDT2s, LDT3s and LDT4s, and MDPVs the standard is 12.5 grams per
mile CO.

(3) These standards do not apply to

interim non-Tier 2 MDPVs.

(h) Certification short test exhaust
emission standards. Certification short test emissions from all gasoline-fueled otto cycle LDV/Ts and MDPVs must not exceed the following standards: (1) Hydrocarbons: 100 ppm as hexane, for certification and SEA testing; 220 ppm as hexane, for in-use testing.

(2) Carbon monoxide: 0.5% for certification and SEA testing; 1.2% for in-use testing.

(3) These standards do not apply to

interim non-Tier 2 MDPVs.

(i) Idle CO standards and references to such standards in this subpart, do not apply to any 2004 or later model year LDV, LDT, or MDPV or to any LDV, LDT
or MDPV certified to Tier 2 standards before model year 2004 for purposes of generating early NO X credits or meeting the requirements of an alternative phase-in schedule that begins prior to the 2004 model year.

(j) Highway NO X exhaust emission
standard. The maximum projected NO X emissions measured on the federal Highway Fuel Economy Test in 40 CFR part 600, subpart B, must not be greater than 1.33 times the applicable FTP NOX standard to which the manufacturer certifies the test group. Both the projected emissions and the product of
the NO X standard and 1.33 must be rounded to the nearest 0.01 g/mi before being compared. This standard is not applicable to MDPVs.

(k) Phase-in of the Tier 2 FTP exhaust and evaporative requirements; small volume manufacturer flexibilities. (1) Manufacturers must comply with the phase-in requirements in Tables S04–7 and S04–8 of this paragraph (k) for the
Tier 2 FTP exhaust emission requirements specified in paragraph (c) of this section. Separate phase-in schedules are provided for LDV/LLDTs
and for HLDT/MDPVs. These requirements specify the minimum percentage of the manufacturer’s LDV/ LLDT and HLDT/MDPV U.S. sales, by model year, that must meet the Tier 2 requirements, including the applicable fleet average standard, for their full
useful lives. As the terms LDV/LLDT and HLDT/MDVP imply, LDVs and LLDTs must be grouped together todetermine compliance with these phasein requirements and HLDTs and MDPVs must also be grouped together todetermine compliance with these phasein requirements. Tables S04–7 and S04–
8 follow:



### TABLE 

### S04–7.—P HASE



### - IN 

### P ERCENT



### AGES FOR 

### LDV/LLDT T IER 

### 2 R E



### QUIREMENTS

Model year Percentage of LDV/
LLDTs that

must meettier 2 requirements

2004 .......................................... 25 

### TABLE 

### S04–7.—P HASE



### - IN 

### P ERCENT



### AGES FOR 

### LDV/LLDT T IER 

### 2 R E



### QUIREMENTS

### —Continued

Model year Percentage of LDV/
LLDTs that

must meettier 2 requirements

2005 .......................................... 50

2006 .......................................... 75 2007 and subsequent ............... 100



### TABLE 

### S04–8.—P HASE



### - IN 

### P ERCENT



### AGES FOR 

### HLDT/MDPV T IER 

### 2 R E



### QUIREMENTS

ModeL year Percentage of HLDT/MDPVs
that must meettier 2 requirements

2008 ...................................... 50 2009 and subsequent ........... 100

(2) Manufacturers must also comply with the phase-in requirements in
Tables S04–7 and S04–8 of this paragraph (k) for the evaporative emission requirements contained in paragraph (e) of this section.

(3) Manufacturers may opt to use
different LDV/LLDTs and HLDT/MDPVs to meet the phase-in requirements for evaporative emissions and FTP exhaust emissions, provided that the
manufacturer meets the minimum applicable phase-in requirements in
Table S04–7 and Table S04–8 of this paragraph (k) for both FTP exhaust and evaporative emissions. A LDV, LDT or MDPV counted toward compliance with any phase-in requirement for FTP exhaust or evaporative standards, must comply with all applicable Tier 2 exhaust requirements or all applicable evaporative requirements, respectively,
described in this section.

(4) LDVs, LDTs and MDPVs not
certified to meet the Tier 2 FTP exhaust requirements during model years 2004– 2008, as allowed under this subpart, are subject to the provisions of paragraph (l)
of this section.

(5) Provisions for small volume manufacturers (i) Small volume manufacturers, as defined in this part, are exempt from the Tier 2 LDV/LLDT exhaust and evaporative emissions phase-in requirements for model years 2004, 2005 and 2006 in Table S04–7 of this paragraph (k), but must comply with the 100% requirement for the 2007 and later model years for exhaust and evaporative emissions. If not complying with Tier 2 requirements during 2004, 2005 and 2006, small volume


### 6859 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

manufacturers must comply with the requirements for interim non-Tier 2
LDV/LLDTs.

(ii) Small volume manufacturers, as defined in this part, are exempt from the HLDT/MDPV exhaust and evaporative phase-in requirement for model year
2008 in Table S04–8 of this section but must comply with the 100% requirement for the 2009 model year.
Small volume manufacturers are also exempt from the HLDT/MDPV interim fleet average NO X standard (0.20 g/mi) and its phase-in for the 2004, 2005 and 2006 model years.

(iii) Small volume manufacturers must comply with the FTP exhaust
emission standards from Tables S04–1 and 2 of paragraph (c) of this section for all HLDT/MDPVs of model years 2004 and later, except that 2004 model year HLDTs may comply with Tier 1 exhaust emission standards subject to the provisions of paragraph (l)(2)(vii) of this section, and 2004 model year MDPVs may comply with heavy-duty vehicle standards subject to the provisions of paragraph (l)(2)(viii) of this section.
Small volume manufacturers must also comply with the 0.20 g/mi fleet average

NO X standard for 2007 and 2008 model year HLDT/MDPVs; the Tier 2 0.07 g/mi fleet average NO X standard for the 2009 and later model year HLDT/MDPVs; and the evaporative emission standards in
Table S04–3 of this section for the 2009 and later model years.

(6)(i) A manufacturer may elect an alternate phase-in schedule that results in 100% phase-in for LDV/LLDTs by 2007. Alternate phase-in schedules must produce a sum of at least 250% when the percentages of LDV/LLDTs certified to Tier 2 requirements for each model year from 2001 through 2007 are summed. As an example, a 10/25/50/65/ 100 percent phase-in that began in 2003 would have a sum of 250 percent and would be acceptable. However, a 10/25/ 40/70/100 percent phase-in that began the same year would have a sum of 245 percent and would not be acceptable.

(ii) A manufacturer electing this option for LDV/LLDTs may calculate its compliance with the evaporative standards in paragraph (e)(1) of this section separately from its compliance with Tier 2 exhaust standards, provided that the phase-in schedules for each separately produce a sum of at least 250 percent when calculated as described in paragraph (k)(6)(i) of this section. A vehicle counted towards compliance with any phase-in requirement for the
Tier 2 exhaust standards or the evaporative standards in paragraph (e)(1) of this section, must comply with all applicable Tier 2 exhaust standards or all evaporative standards, as applicable, described in this section.

(iii) In addition to the requirements of paragraphs (k)(6)(i) and (ii) of this section, except as permitted in paragraph (k)(6)(vii) of this section, a manufacturer of LDV/LLDTs electing to use an alternate phase-in schedule for compliance with the Tier 2 exhaust standards or the evaporative standards in paragraph (e)(1) of this section must ensure that the sum of the percentages of vehicles from model years 2001 through 2004, meeting such exhaust or evaporative standards, as applicable, is at least 25%.

(iv) A manufacturer may elect an alternate phase-in schedule that results in 100% phase-in for HLDT/MDPVs by 2009. The requirements of paragraphs (k)(6)(i) through (k)(6)(ii) of this section apply, except that for HLDT/MDPVs, the calculation described in paragraphs (k)(6)(i) and (k)(6)(ii) of this section may cover model years 2001 through 2009 and must produce a sum of at least 150%.

(v) A manufacturer electing to use any alternate phase-in schedule permitted under this section must provide in its Application for Certification for the first year in which it intends to use such a schedule, and in each succeeding yearduring the phase-in, the intended phasein percentages for that model year and the remaining phase-in years along with
the intended final sum of those percentages as described in this paragraph (k)(6). This information may
be included with the information required under § 86.1844–01(d)(13). In its year end annual reports, as required under § 86.1844–01(e)(4) the
manufacturer must include sufficient
information so that the Administrator can verify compliance with the alternative phase-in schedule established under paragraph (k)(6) of
this section.

(vi) Under an alternate phase-in schedule, the projected phase-in percentage is not binding for a given model year, provided the sums of the actual phase-in percentages that occur meet the appropriate total sums as required in paragraph (k)(6) of this section, and provided that 100% actual compliance is reached for the appropriate model year, either 2007 or 2009, as described in paragraph (k)(6) of
this section.

(vii) A manufacturer unable to meet the 25% requirement in paragraph (k)(6)(iii) of this section, must:

(A) Ensure that the sum of the percentages of vehicles for model years 2001 through 2004, meeting such exhaust or evaporative standards, as applicable, is at least 20%. (B) Subtract that sum of percentages for model years 2001 through 2004 from 25%, and multiply the unrounded result by 2.

(C) Round the product from paragraph (k)(6)(vii)(B) of this section to the nearest 0.1% and add that to 50%. That sum becomes the required phase-in percentage for the 2005 model year.

(D) Comply with the phase-in percentage for the 2005 model year determined in paragraph (k)(6)(vii)(C) of
this section.

(E) Comply with a minimum phase-in percentage for the 2006 model year determined by the following equation: minimum phase-in percentage for 2006 = [75% ¥ (2005 api ¥ 2005 rpi)]

Where:

2005 rpi = the required phase-in for the 2005 model year as determined in paragraph (k)(6)(vii)(C) of this section; and

2005 api = the manufacturer’s actual phase-in quantity for the 2005 model year. (7)(i) Sales percentages for the purpose of determining compliance with the phase-in of the Tier 2 requirements and the phase-in of the evaporative standards in paragraph (e)(1) of this section, must be based upon projected U.S. sales of LDV/LLDTs and HLDT/MDPVs of the applicable model year by the manufacturer to the point of first sale. Such sales percentages must be rounded to the nearest one tenth of a percent, and must
not include vehicles and trucks projected to be sold to points of first sale in California or a state that has adopted California requirements for that model year as permitted under section 177 of
the Act.

(ii) Alternatively, the manufacturer may petition the Administrator to allow actual volume produced for U.S. sales to be used in lieu of projected U.S. sales for purposes of determining compliance with the phase-in percentage requirements under this section. The manufacturer must submit its petition within 30 days of the end of the model year to the Vehicle Programs and Compliance Division. For EPA to approve the use of actual volume produced for U.S. sales, the
manufacturer must establish to the satisfaction of the Administrator, that actual production volume is functionally equivalent to actual sales
volume of LDV/LLDTs and HLDT/
MDPVs sold in states other than California and states that have adopted
California standards.

(iii) Manufacturers must submit information showing compliance with all phase-in requirements of this section


### 6860 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

with its Part I application as required by § 86.1844(d)(13).

(l) FTP exhaust standards for interim
non-Tier 2 vehicles.—(1) FTP exhaust emission standards for interim non-Tier
2 LDV/LLDTs. (i) LDV/LLDTs that are not used to meet the Tier 2 phase-in requirements including the Tier 2 fleet average NO X requirement during the Tier 2 phase-in period (model years 2004–2006) must comply with the full
useful life FTP exhaust emission
standards listed in Table S04–1 of paragraph (c) of this section and the corresponding intermediate useful life standards, if any, in Table S04–2 of paragraph (c) of this section. Manufacturers may choose the bin of full useful life standards to which they certify a test group of vehicles, subject to the requirements in paragraph (l)(3)(i) of this section. In a given model year, an individual vehicle may not be used to comply with both the Tier 2 fleet average NO X standard and the applicable interim fleet average NO X standard although vehicles from the same test group may be separated and the vehicles counted toward compliance with either program.

(ii) The provisions of paragraphs (c) (1), (2) and (3) of this section apply to flexible-fueled, dual fuel and multi-fuel
interim non-Tier 2 LDV/LLDTs.

(iii) Only manufacturers that comply with the applicable FTP standards in Tables S04–1 and 2 of paragraph (c) of
this section for all of their 2004 model year HLDTs and declare their intention to comply with the 2004 model year 25% phase-in requirement to the 0.20 g/ mi interim fleet average NO X standard for HLDTs (or HLDT/MDPVs) described in this paragraph (l) may use the optional higher NMOG values for
interim LDT2s certified to bin 9
standards that are shown in Tables S04–
1 and 2. Manufacturers must declare their intention to comply with the full 2004 model year 25% phase-in requirement in Part I of their HLDT or their HLDT/MDPV, as applicable, certification applications.

(iv) The provisions of paragraph (c)(4) of this section apply to interim non-Tier
2 vehicles.

(2) FTP exhaust emission standards for interim non-Tier 2 HLDTs and

interim non-Tier 2 MDPVs. (i) Except as permitted under paragraphs (l)(2) (vii) and (viii) of this section, HLDTs and MDPVs of model years 2004–2008 that
are not used to meet the Tier 2 FTP phase-in requirements including the Tier 2 fleet average NO X requirement must comply with the full useful life
FTP exhaust emission standards listed in Table S04–1 of paragraph (c) of this section and, the corresponding intermediate useful life standards, if any, in Table S04–2 of paragraph (c) of this section. Manufacturers may choose
the bin of full useful life standards to which they certify a test group of vehicles, subject to the requirements in paragraph (l)(3)(ii) of this section.

(ii) Except as permitted under paragraphs (l)(2) (vii) and (viii) of this section, HLDTs and MDPVs of model years 2004–2008 that are not used to meet the Tier 2 FTP phase-in requirements including the Tier 2 fleet average NO X requirement must comply with the fleet average NO X standard described in paragraph (l)(3)(ii) of this section subject to the phase-in schedule in paragraph (l)(2)(iv) of this section, i.e. 25 percent of the HLDT and MDPVs must meet the fleet average standard of 0.20 g/mi in 2004, 50 percent in 2005,
and so on.

(iii) Manufacturers may choose the
bin of full useful life standards and corresponding intermediate life standards to which they certify test groups of HLDTs and MDPVs, subject to the requirements in paragraph (l)(3)(ii) of this section. Manufacturers may
include HLDT/MDPVs in the interim program that are not used to meet the Tier 2 fleet average NO X standard or the phase-in percentage requirements in the Tier 2 program or to generate Tier 2

NO X credits. In a given model year, an individual vehicle may not be used to comply with both the Tier 2 fleet average NO X standard and the applicable interim fleet average NO X standard although vehicles from the same test group may be separated and the vehicles counted toward compliance with either program.

(iv) Phase-in schedule for interim
non-Tier 2 HLDT/MDPVs. Table S04–9 of this paragraph (l) specifies the minimum percentage of the
manufacturer’s interim non-Tier 2 HLDT/MDPV U.S. sales, by model year, that must comply with the fleet average

NO X standard described in paragraph (l)(3)(ii) of this section. Table S04–9
follows:



### Table S04–9.—Phase-in Percentages for Compliance With Interim Non-Tier 2 Fleet Average NOX 

### Standard for HLDT/MDPVs

Model year Percentage of
non-tier 2 HLDT/MDPVs
that must meet interim non-tier 2 fleet average NOX standard

2004 ...................................... 25

2005 ...................................... 50

2006 ...................................... 75 

### Table S04–9.—Phase-in Percentages for Compliance With Interim Non-Tier 2 Fleet Average NOX

### Standard for HLDT/MDPVs—Continued

Model year Percentage of
non-tier 2 HLDT/MDPVs
that must meet interim non-tier 2 fleet average NOX standard

2007 and 2008 ..................... 100

(v)(A) A manufacturer may elect an alternate phase-in schedule, beginning as early as the 2001 model year, that results in 100% compliance by 2007 with the fleet average NO X standard for
interim non-Tier 2 HLDT/MDPVs described in paragraph (l)(3)(ii) of this section. The requirements of paragraph (k)(6) of this section apply to the selection of an alternate phase-in
schedule.

(B) If a manufacturer elects not to bring all of its HLDT/MDPVs into compliance with the interim requirements in 2004 as permitted under paragraphs (l)(2)(vii) and

(viii) of this section, it may still use an alternate phase-in schedule to attain 100% compliance with the interim fleet average NO X standard for HLDT/ MDPVs, but the sum of phase-in percentages it must meet will be 225% rather than 250%. If the manufacturer commences its 2004 model year on or after December 21, 2003, for any HLDT/ MDPVs, the manufacturer must increase the 225% by the fraction of its 2004 model year HLDT/MDPVs whose model year commenced on or after that date and which were brought into compliance with the 0.20 g/mi corporate average NO X standard as required under paragraph (l)(2)(ix) of this section. The
manufacturer must ensure that the sum of the percentages of vehicles up through model year 2005 complying with the interim fleet average NOX standard is at least 50%.

(vi) The provisions of paragraphs (c) (1), (2) and (3) of this section apply to flexible-fueled, dual fuel and multi-fuel
interim non-Tier 2 HLDT/MDPVs.

(vii) For 2004 model year HLDT test groups whose model year commences before December 21, 2003, the manufacturer may exempt such HLDTs from compliance with any requirements applicable to interim non-Tier 2 HLDTs, and such HLDTs must be produced in
accordance with standards and requirements in §§ 86.1814–02 and §§ 86.1815–02. Such HLDTs must also meet the refueling emission standards


### 6861 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

contained in paragraph (e)(3) of this

section.

(viii) For 2004 model year heavy-duty vehicles whose model year commences before December 21, 2003, the manufacturer may exempt such vehicles from compliance with any requirements applicable to interim non-Tier 2 MDPVs. Exempted vehicles will not be
considered MDPVs and must be produced in accordance with standards and requirements in § 86.099–10. Exempted vehicles are also exempted from refueling emission standards.

(ix) For 2004 model year HLDT and MDPV test groups whose model year commences on or after December 21, 2003, the manufacturer must comply with all interim non-Tier 2 requirements
in this section.

(A) All such vehicles, but not more than 25% of the manufacturer’s total sales of 2004 model year HLDT/MDPVs
must meet the interim non-Tier 2 fleet average NO X standard as described in paragraph (l)(3)(ii) of this section.

(B) All such vehicles but not more than 40% of the manufacturer’s 2004 model year HLDT/MDPVs must comply with the refueling requirements in paragraph (e)(3) of this section.

(x) Only those manufacturers that comply with the interim non-Tier 2 FTP
standards for all of their 2004 model year HLDTs and declare their intention to comply with the 2004 model year 25% phase-in requirement to the fleet average interim NO X standard for HLDTs or HLDT/MDPVs of 0.20 g/mi described in paragraph (l) of this section may use the optional higher NMOG
values for interim LDT4s certified to bin
10 standards that are shown in Tables S04–1 and 2 of paragraph (c) of this
section. Manufacturers must declare their intention to comply with the 2004 model year 25% phase-in requirement
in Part I of their HLDT certification applications.

(xi) Only those manufacturers that comply with the interim non-Tier 2 FTP
standards for all of their 2004 model year MDPVs, and declare their intention to comply with the 2004 model year 25% phase-in requirement to the fleet average interim NO X standard for MDPVs or HLDT/MDPVs of 0.20 g/mi described in paragraph (l) of this section

may:

(A) Use the exhaust emission
standards of bin 11 in Tables S04–1 and S04–2 of paragraph (c) in this section for MDPVs through model year 2008;

(B) For diesel-fueled vehicles, certify the engines in such vehicles, through model year 2007, to provisions in this part 86 applicable to diesel-fueled heavy-duty engines of the appropriate model year. Such diesel fueled vehicles must not be included in any count or determination of compliance with the phase-in requirements applicable to interim non-Tier 2 MDPVs; and

(C) Use the optional higher NMOG
values for interim LDT4s certified to bin
10 standards that are shown in Tables
S04–1 and 2.

(xii) Manufacturers electing to comply with the provisions of paragraph (l)(2)(xi) of this section must declare their intention to comply with the 2004 model year 25% phase-in requirement to the fleet average interim NOX standard for MDPVs or HLDT/MDPVs of 0.20 g/mi in Part I of their MDPV certification applications.

(xiii) Where diesel-fueled heavy-duty engines are used as permitted under paragraph (l)(2)(xi)(B) of this section, such engines must be treated as a separate averaging set—MDPV HDDEs— under the averaging, banking andtrading provisions applicable to heavyduty diesel engines. Only NO X credits generated by engine-certified diesel engines that are used in other MDPVs can be applied to these engines. Manufacturers wishing to average, bank
or trade credits for MDPV HDDEs must comply with the requirements in this paragraph and with all requirements applicable to heavy-duty engine averaging, banking and trading in this part.

(3) Fleet average NO X standards for
interim non-Tier 2 LDV/Ts and MDPVs. (i) Manufacturers must comply with a fleet average full useful life NOX standard for their interim non-Tier 2 LDV/LLDTs, on an annual basis, of 0.30 grams per mile.

(ii) Manufacturers must comply with a fleet average full useful life NOX standard for their interim non-Tier 2 HLDT/MDPVs, excluding those HLDTs and MDPVs not yet covered by the phase-in requirement described in paragraph (l)(2)(ii) of this section, on an annual basis, of 0.20 grams per mile.

(iii) Manufacturers must determine their compliance with these interim fleet average NO X standards for each model year by separately computing the sales weighted average NO X level of all
interim non-Tier 2 LDV/LLDTs and all
interim non-Tier 2 HLDT/MDPVs (excluding those not yet phased in as described in paragraph (l)(2)(ii) of this section), using the methodology in § 86.1860.

(iv) Manufacturers may generate, bank, average, trade and use interim

non-Tier 2 NO X credits based on their

NO X fleet average as determined under paragraph (l)(3)(iii) of this section. Unless waived or modified by the Administrator, the provisions of § 86.1861 of this part apply to the generation, banking, averaging, trading and use of credits generated by interim
non-Tier 2 vehicles. NO X credits generated by interim non-Tier 2 vehicles are not subject to any discount except as required by § 86.1861–04(e).

(m) NMOG standards for diesel, flexible fueled and dual-fueled LDV/Ts
and MDPVs. (1) For diesel fueled LDV/ Ts and MDPVs, the term ‘‘NMOG’’ in
both the Tier 2 and interim non-Tier 2
standards means non-methane hydrocarbons.

(2) Flexible-fueled and dual-fuel Tier
2 and interim non-Tier 2 vehicles must
be certified to NMOG exhaust emission standards both for operation on gasoline and on any alternate fuel they are designed to use. Manufacturers may
measure NMHC in lieu of NMOG when
flexible-fueled and dual-fuel vehicles are operated on gasoline, subject to the requirements of § 86.1810(p).

(n) Hybrid electric vehicle (HEV) and Zero Emission Vehicle (ZEV) requirements. For FTP and SFTP exhaust emissions, and unless otherwise approved by the Administrator,
manufacturers must measure emissions from all HEVs and ZEVs according to the requirements and test procedures
found in the document entitled
California Exhaust Emission Standards
and Test Procedures for 2003 and Subsequent Model Zero-Emission Vehicles and 2001 and Subsequent Model Hybrid Electric Vehicles, in the Passenger Car, Light-duty Truck and Medium-duty Vehicle Classes. This document is incorporated by reference (see § 86.1) . Requirements and procedures in this document that are relevant only to complying with the California ZEV mandate, computing partial and full ZEV allowance credits, or generating and using ZEV credits, are not relevant to the federal program and may be disregarded. Discussion in that document relevant to fleet average
NMOG standards and NMOG credits may also be disregarded.

(o) NMOG measurement. (1)
Manufacturers must measure NMOG
emissions in accordance with Part G of the California Non-Methane Organic Gas Test Procedures. These requirements are incorporated by reference (see § 86.1).

(2) Manufacturers must not apply reactivity adjustment factors (RAFs) to NMOG measurements. See § 86.1841.

(p) In-use standards. (1) Table S04–10 of this paragraph (p) contains in-use emission standards applicable only to
vehicles certified to the bins shown inthe table. These standards apply to inuse testing performed by the manufacturer pursuant to regulations at §§ 86.1845–01, 86.1845–04 and 86.1846–01 and to in-use testing


### 6862 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

performed by EPA. These standards do not apply to certification or Selective Enforcement Auditing.

(2) These standards apply only to LDV/LLDTs produced up through the 2008 model year, and HLDT/MDPVs produced up through the 2010 model year. These standards are subject to other limitations described in paragraph (p)(3) of this section.

(3) For the first model year and also for the next model year after that, in which a test group of vehicles is
certified to a bin of standards to which it has not previously been certified, the
standards in Table S04–10 of this paragraph (p) apply for purposes of inuse testing only. The standards apply equally to all LDV/Ts and MDPVs subject to the model year limitation in paragraph (p)(2) of this section. Table

S04–10 follows:



### TABLE 

### S04–10—I N



### - USE 

### C OMPLIANCE 

### STANDARDS 

### ( G

### /MI 

### )

[Certification standards shown for reference purposes]

Bin number Durability period (miles) NOX In-use NOX certification NMOG In-use NMOG certification

5 .............................. 50,000 0.07 0.05 n/a ........................... 0.075 5 .............................. 120,000 0.10 0.07 n/a ........................... 0.090 4 .............................. 120,000 0.06 0.04 n/a ........................... 0.070 3 .............................. 120,000 0.05 0.03 0.09 ......................... 0.055 2 .............................. 120,000 0.03 0.02 0.02 ......................... 0.010

(4) For diesel vehicles certified to bin 10, separate in-use standards apply for

NO X and PM emissions. These standards are determined by multiplying the applicable NO X and PM certification standards by factors of 1.2 and 1.35, respectively, and then rounding the result to one more decimal place than contained in the certification
standard. The resultant standards do not apply for certification or selective enforcement auditing.

(q) Hardship provision for small volume manufacturers. (1) A small volume manufacturer may apply for relief from any applicable final phase-in model year contained in this section. Relief will only be available to defer required compliance with a completely new set of standards, a fleet average

NO X standard, and/or evaporative emission standard for 100% of affected vehicles for one model year. Thus, a
small volume manufacturer that obtains relief may:

(i) Defer 100% compliance with the fleet average NO X standard for interim LDV/LLDTs (0.30 g/mi) until 2005;

(ii) Defer 100% compliance with the evaporative emission standards and/or fleet average NO X standard for Tier 2 LDV/LLDTs (0.07 g/mi) until 2008;

(iii) Defer 100% compliance with the requirements that interim HLDTs and MDPVs comply with applicable
emission standards shown in Tables S04–1 and S04–2, until 2005;

(iv) Defer 100% compliance with the fleet average NO X standard for interim HLDT/MDPVs (0.20 g/mi) until 2008;
and

(v) Defer 100% compliance with the the evaporative emission standards and/ or fleet average NO X standard for Tier 2 HLDT/MDPVs (0.07 g/mi) until 2010.

(2) Applications for relief must be in writing and must:

(i) Be submitted before the earliest date of noncompliance; (ii) Include evidence that the
manufacturer will incur severe economic hardship if relief is not granted;

(iii) Include evidence that the noncompliance will occur despite the
best efforts of the manufacturer to comply; and

(iv) Include evidence that the manufacturer has made every reasonable effort to purchase credits to address the noncompliance, where applicable.

(r) NMOG standard adjustment for direct ozone reducing devices. (1) A manufacturer may obtain NMOG credit for use in certifying to the exhaust NMOG standards listed in paragraph (c) of this section and for use in complying with the in-use standards of paragraph (p) of this section, where applicable. This credit effectively allows the
manufacturer to increase the exhaust
NMOG emission standards listed in these paragraphs by the amount of the applicable credit. For example, if the applicable NMOG credit was 0.01 g/mi, and the vehicle was being certified in Bin 5, as described in Table S04–1 of paragraph (c) of this section, exhaust NMOG emissions must be no greater than 0.10 g/mi, as opposed to the
normal NMOG certification standard of 0.09 g/mi in Bin 5.

(2) The NMOG credit must be determined through a two-step process.

(i) The first step must determine the ozone reduction potential of the direct ozone reducing device, the ozone reduction potential of exhaust NMOG reductions beyond Bin 5 of the Tier 2 standards, and the ratio of the two methods of reducing ambient ozone levels. The requirements for this step are described in paragraph (r)(3) of this

section.

(ii) The second step must demonstrate and certify the relevant performance characteristics of the specific ozone reducing device. The requirements for this step are described in paragraph (r)(4) of this section.

(3) The ozone reduction potential of the direct ozone reducing device and the ozone reduction potential of exhaust NMOG reductions beyond Bin 5 of the
Tier 2 standards must be estimated using procedures which are approved by the Administrator in advance. At a

minimum:

(i) The modeling must utilize an urban airshed model using up-to-date chemical and meteorological simulation techniques;

(ii) Four local areas must be modeled: New York City, Chicago, Atlanta and
Houston;

(iii) The ozone episodes to be
modeled must meet the selection criteria established by EPA for State ozone SIPs;

(iv) Photochemical and dispersion modeling must follow that used by EPA to project the ozone impacts of this rule, or its equivalent;

(v) Emission projections must be made for calendar year 2007 and be consistent with those used by EPA in support of this final rule, or reflect updates approved by EPA;

(vi) Baseline emissions (emissions prior to use of the direct ozone reducing device or the VOC emission reductions)
must include the benefits of the Tier 2 emission and sulfur standards; as well
as all other emission controls assumed in EPA’s ozone modeling of the benefits of the Tier 2 and sulfur standards, as described in the Final Regulatory Impact Analysis to the Tier 2 and Sulfur Rule;

(vii) The ozone benefit of the direct ozone reducing device must assume a radiator area of 0.29 square meters, an air flow velocity through the radiator of 40% of vehicle speed, and an ozone reduction efficiency of 80%, or other


### 6863 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

values as approved by the Administrator;

(viii) The ozone level of the air entering the direct ozone reducing device must be assumed to be 40% less than that existing in the grid cell where the vehicle is located;

(ix) The ozone benefit of VOC
emission reductions must be modeled by assuming that all Tier 2 LDVs, LDTs
and MDPVs meet an exhaust NMOG standard of 0.055 g/mi or lower instead of a 0.09 g/mi NMOG standard;

(x) The ozone reducing device must be assumed to be present on all of the Tier 2 LDVs, LDTs and MDPVs modeled as meeting the more stringent NMOG standard described in paragraph (r)(3)(ix) of this section;

(xi) The relationship between changes
in exhaust NMOG emission standards
and in-use VOC emissions must be determined sufficiently far in the future to ensure that the change in ozone being modeled is sufficiently large to allow comparison with the impact of the ozone reducing device;

(xii) LDV, LDT and MDPV emissions must be modeled using the updated Tier 2 emission model developed by EPA as part of the Tier 2 rulemaking (available from EPA upon request) or MOBILE6, once this model is available;

(xiii) The ozone benefit of the direct ozone reducing device must be the reduction in the peak one-hour ozone level anywhere in the modeled region on the day when ozone is at its highest;

(xiv) The NMOG credit in each local area must be the reduction in peak one
hour ozone associated with use of the direct ozone reducing device divided by the reduction in peak one hour ozone associated with the more stringent
exhaust NMOG emission standard multiplied by the reduction the exhaust NMOG standard (in g/mi) modeled in paragraph (r)(3)(ix) of this section; and

(xv) The NMOG credit applicable to the generic direct ozone reducing device modeled in paragraph (r)(3)(vii) of this section must be determined by arithmetically averaging the NMOG credit determined in paragraph (r)(3)(xiv) of this section for each of the
four local areas.

(4) The manufacturer must submit data, using procedures which have been approved by the Administrator in advance, that demonstrate the following aspects of the device being certified:

(i) The air flowrate through the device as a function of vehicle speed;

(ii) The ozone reduction efficiency of
the device over the useful life of the vehicle for a range of vehicle speeds and ozone levels; (iii) The method through which the onboard diagnostic system will detect improper performance.

(5) The NMOG credit for the specific application of this technology tested under the provisions of paragraph (r)(4)
of this section is the four-area NMOG credit determined in paragraph (r)(3)(xv)
of this section scaled based on the performance of the specific application tested under the provisions of paragraph (r)(4) of this section relative to those assumed in paragraph (r)(3)(vii) of this section. This scaling must assume a linear relationship between the NMOG credit and three aspects of the direct ozone reducing device: radiator area, average air flow through the radiator relative to vehicle speed, and ozone reduction efficiency and the NMOG
credit. The NMOG credit must be rounded to the nearest 0.001 g/mi. For example, if the NMOG credit determined in paragraph (r)(3)(xv) of this section was 0.01 g/mi and the specific direct ozone reducing device being certified had an area of 0.20 square meters, an air flow velocity of 30% of vehicle speed and an ozone reducing efficiency of 70%, and the generic ozone reducing device
simulated in the ozone model under paragraph (r)(3)(vii) of this section had an area of 0.29 square meters, an air flow velocity of 40% of vehicle speed and an ozone reducing efficiency of 80%, the NMOG credit applicable to the specific device being certified would be:
0.01 g/mi * (0.20/0.29) * (30%/40%) * 70%/80%) = 0.005

25. Section 86.1812–01 is amended by adding a sentence to the end of the introductory text to read as follows:

§ 86.1812–01 Emission standards for lightduty trucks 1.

* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811–04.

* * * * *

26. Section 86.1813–01 is amended by adding a sentence to the end of the introductory text to read as follows:

§ 86.1813–01 Emission standards for lightduty trucks 2.

* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811–04.

* * * * *

27. Section 86.1814–02 is amended by adding a sentence to the end of the introductory text to read as follows: § 86.1814–02 Emission standards for lightduty trucks 3.

* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811–04.

* * * * *

§ 86.1814–04 [Removed]

28. Section 86.1814–04 is removed. 29. Section 86.1815–02 is amended by adding a sentence to the end of the introductory text to read as follows:

§ 86.1815–02 Emission standards for lightduty trucks 4.

* * * This section does not apply to 2004 and later model year vehicles, except as specifically referenced by § 86.1811–04.

* * * * *

§ 86.1815–04 [Removed]

30. Section 86.1815–04 is removed. 31. Section 86.1824–01 is amended by revising the first sentence of the introductory text and adding paragraphs (a)(2)(iii), (a)(2)(iv) and (a)(2)(v) to read
as follows:

§ 86.1824–01 Durability demonstration procedures for evaporative emissions.

This section applies to gasoline-, methanol-, liquefied petroleum gas-, and natural gas-fueled LDV/Ts and MDPVs.

***

(a) * * * (2) * * * (iii) For gasoline fueled vehicles certified to meet the evaporative
emission standards set forth in § 86.1811–04(e)(1), any service accumulation method for evaporative emissions must employ gasoline fuel for the entire service accumulation period which contains ethanol in, at least, the highest concentration permissible in gasoline under federal law and that is commercially available in any state in
the United States. Unless otherwise approved by the Administrator, the
manufacturer must determine the appropriate ethanol concentration by selecting the highest legal concentration commercially available during the calendar year before the one in which the manufacturer begins its service
accumulation. The manufacturer must also provide information acceptable to
the Administrator to indicate that the
service accumulation method is of sufficient design, duration and severityto stabilize the permeability of all nonmetallic fuel and evaporative system components to the service accumulation
fuel constituents.

(iv) For flexible-fueled, dual-fueled, multi-fueled, ethanol-fueled and
methanol-fueled vehicles certified to


### 6864 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

meet the evaporative emission standards set forth in § 86.1811–04(e)(1), any
service accumulation method must employ fuel for the entire service accumulation period which the vehicle is designed to use and which the
Administrator determines will have the greatest impact upon the permeability of evaporative and fuel system components. The manufacturer must also provide information acceptable to
the Administrator to indicate that the
service accumulation method is of sufficient design, duration and severityto stabilize the permeability of all nonmetallic fuel and evaporative system components to service accumulation
fuel constituents.

(v) A manufacturer may use other methods, based upon good engineering judgment, to meet the requirements of paragraphs (a)(2) (iii) and (iv) of this section, as applicable. These methods must be approved in advance by the Administrator and meet the objectives of paragraphs (a)(2) (iii) and (iv) of this section, as applicable: to provide assurance that the permeability of all non-metallic fuel and evaporative system components will not lead to evaporative emission standard exceedance under sustained exposure tocommercially available alcoholcontaining fuels for the useful life of the
vehicle.

* * * * *

32. Section 86.1827–01 is amended by adding paragraph (e) to read as follows:

§ 86.1827–01 Test group determination.

* * * * *

(e) Unless otherwise approved by the Administrator, a manufacturer of hybrid electric vehicles must create separate test groups based on both the type of battery technology employed by the HEV and upon features most related to
their exhaust emission characteristics.

33. Section 86.1829–01 is amended by adding paragraphs (b)(1)(iii)(E) and (d)
to read as follows:

§ 86.1829–01 Durability and emission testing requirements; waivers.

* * * * *

(b) * * * (1) * * *
(iii) * * * (E) In lieu of testing a gasoline or
diesel fueled Tier 2 or interim non-Tier 2 vehicle for formaldehyde emissions
when such vehicles are certified based upon NMHC emissions, a manufacturer may provide a statement in its application for certification that such vehicles comply with the applicable
standards. Such a statement must be based on previous emission tests, development tests, or other appropriate
information.

* * * * *

(d)(1) Beginning in the 2004 model year, the exhaust emissions must be
measured from all LDV/T exhaust
emission data vehicles tested in accordance with the federal Highway Fuel Economy Test (HWFET; 40 CFR part 600, subpart B). The oxides of nitrogen emissions measured during such tests must be multiplied by the oxides of nitrogen deterioration factor computed in accordance with § 86.1823–01 and subsequent model year provisions, and then rounded and compared with the applicable emission standard in § 86.1811–04. All data obtained from the testing required under this paragraph (d) must be reported in accordance with the procedures for reporting other exhaust emission data required under this subpart.

(2) In the event that one or more
emission data vehicles fail the applicable HWFET standard in § 86.1811–04, the manufacturer may submit to the Administrator engineering data or other evidence showing that the system is capable of complying with the standard. If the Administrator finds, on the basis of an engineering evaluation, that the system can comply with the HWFET standard, he or she may accept the information supplied by the
manufacturer in lieu of the test data.

(3) The provisions of paragraphs (d)(1) and (d)(2) of this section do not apply

to MDPVs.

34. Section 86.1837–01 is amended by designating the existing text as paragraph (a) and by adding paragraph (b) to read as follows:

§ 86.1837–01 Rounding of emission

measurements.

* * * * *

(b) Fleet average NO X value calculations, where applicable, must be rounded before comparing with the applicable fleet average standard and calculating credits generated or needed
as follows: manufacturers must round to the same number of significant figures that are contained in the quantity of
vehicles in the denominator of the equation used to compute the fleet average NO X emissions, but to no less than one more decimal place than that of the applicable fleet average standard.

35. Section 86.1838–01 is amended by revising paragraphs (b)(1)(i) and (c)(2)(iii) to read as follows:

§ 86.1838–01 Small volume manufacturer certification procedures.

* * * * *

(b) * * * (1) * * * (i) The optional small-volume manufacturers certification procedures apply to LDV/Ts and MDPVs produced by manufacturers with U.S. sales, including all vehicles and engines imported under provisions of 40 CFR 85.1505 and 85.1509 (for the model year in which certification is sought) of fewer than 15,000 units (LDV/Ts, MDPVs, heavy-duty vehicles and heavy-duty engines combined).

* * * * *

(c) * * * (2) * * * (iii) The provisions of § 86.1845– 01(c)(2) and § 86.1845–04(c)(2) that require one vehicle of each test group during high mileage in-use verification testing to have a minimum odometer mileage of 75 percent of the full useful life mileage for Tier 1 and NLEV LDV/ Ts, or 90,000 (or 105,000) miles for Tier 2 and interim non-Tier 2 vehicles, do not apply.

* * * * *

36. Section 86.1840–01 is amended by adding paragraphs (c) and (d) to read as
follows:

§ 86.1840–01 Special test procedures.

* * * * *

(c) Manufacturers of vehicles equipped with periodically regenerating trap oxidizer systems must propose a procedure for testing and certifying such vehicles including SFTP testing for the review and approval of the
Administrator. The manufacturer must submit its proposal before it begins any
service accumulation or emission testing. The manufacturer must provide with its submittal, sufficient
documentation and data for the Administrator to fully evaluate the operation of the trap oxidizer system and the proposed certification and testing procedure.

(d) The provisions of paragraphs (a) and (b) of this section also apply to

MDPVs.

37. Section 86.1841–01 is amended by revising paragraph (a)(1)(iii) and adding paragraph (e) to read as follows:

§ 86.1841–01 Compliance with emission standards for the purpose of certification.

(a) * * * (1) * * * (iii) For the SFTP composite standard
of NMHC+NO X , the measured results of
NMHC and NO X must each be adjusted by their corresponding deterioration factors before the composite

NMHC+NO X certification level is calculated. Where the applicable FTP exhaust hydrocarbon emission standard is an NMOG standard, the applicable
NMOG deterioration factor must be used in place of the NMHC deterioration


### 6865 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

factor, unless otherwise approved by the
Administrator.

* * * * *

(e) Unless otherwise approved by the Administrator, manufacturers must not use Reactivity Adjustment Factors (RAFs) in their calculation of the certification levels of any pollutant, regardless of the fuel used in the test
vehicle.

38. Section 86.1844–01 is amended by adding new paragraphs (d)(15), (d)(16), (e)(6) and (i) to read as follows:

§ 86.1844–01 Information requirements: Application for certification and submittal of information upon request.

* * * * *

(d) * * * (15) For HEVs, unless otherwise approved by the Administrator, the information required by the ‘‘California
Exhaust Emission Standards and Test Procedures for 2003 and Subsequent Model Zero-Emission Vehicles, and 2001 and Subsequent Model Hybrid Electric Vehicles, in the Passenger Car, Light-Duty Truck and Medium-duty Vehicle Classes’’ must be supplied. These procedures are incorporated by reference (see § 86.1).

(16) (i) For Tier 2 and interim nonTier 2 vehicles beginning with the 2004 model year, a statement indicating that
the manufacturer has conducted an engineering analysis of the complete exhaust system to ensure that the exhaust system has been designed:

(A) To facilitate leak-free assembly, installation and operation for the full useful life of the vehicle; and

(B) To facilitate that such repairs as might be necessary on a properly
maintained and used vehicle can be performed in such a manner as to maintain leak-free operation, using tools commonly available in a motor vehicle dealership or independent repair shop
for the full useful life of the vehicle.

(ii) The analysis must cover the exhaust system and all related and attached components including the air injection system, if present, from the engine block manifold gasket surface to a point sufficiently past the last catalyst and oxygen sensor in the system to assure that leaks beyond that point will not permit air to reach the oxygen sensor or catalyst under normal operating conditions.

(iii) A ‘‘leak-free’’ system is one in which leakage is controlled so that it
will not lead to a failure of the
certification exhaust emission standards

in-use.

(iv) The provisions of paragraphs (d)(16)(i) and (ii) do not apply to
vehicles whose certification is carried over from the NLEV program or carried across from the Cal LEV I program.

(e) * * * (6) The NMOG/NMHC and HCHO to NMHC ratios established according to § 86.1845–04.

* * * * *

(i) For exhaust emission testing for Tier 2 and interim non-Tier 2 vehicles, if approved by the Administrator in advance, manufacturers may submit exhaust emission test data generated under California test procedures tocomply with any certification and inuse testing requirements under this subpart. The Administrator may require supporting information to establish that
differences between California and Federal exhaust testing procedures and fuels will not produce significant
differences in emission results. The Administrator may require that in-use testing be performed using Federal test fuels as specified in § 86.113–04(a)(1).

39. Section 86.1845–04 is amended by:

a. revising paragraph (a), b. revising paragraph (c)(2), and c. adding paragraph (f).
The revisions and additions read as
follows:

§ 86.1845–04 Manufacturer in-use verification testing requirements

(a) General requirements. (1) A manufacturer of LDVs, LDTs and/or MDPVs must test, or cause to have tested, a specified number of LDVs, LDTs and MDPVs. Such testing must be
conducted in accordance with the provisions of this section. For purposes of this section, the term vehicle includes light-duty vehicles, light-duty trucks and medium-duty vehicles.

(2) Unless otherwise approved by the Administrator, no emission
measurements made under the requirements of this section may be adjusted by Reactivity Adjustment Factors (RAFs).

(3) Upon a manufacturer’s written request, prior to in-use testing, that presents information to EPA regarding pre-conditioning procedures designed solely to remove the effects of high sulfur in gasoline from vehicles produced through the 2007 model year, EPA will consider allowing such procedures on a case-by-case basis. EPA’s decision will apply to manufacturer in-use testing conducted under this section and to any in-use testing conducted by EPA.

* * * * *

(c) * * * (2) Vehicle mileage: (i) All test vehicles must have a minimum odometer mileage of 50,000
miles. At least one vehicle of each test group must have a minimum odometer mileage of 75 percent of the full useful life mileage. See § 86.1838–01(c)(2) for small volume manufacturer mileage requirements; or

(ii) For engine families certified for a useful life of 150,000 miles, at least one
vehicle must have a minimum odometer mileage of 105,000 miles. See § 86.1838–01(c)(2) for small volume manufacturer mileage requirements.

* * * * *

(f)(1) A manufacturer may conduct inuse testing on a test group by measuring
NMHC exhaust emissions rather than
NMOG exhaust emissions. The
measured NMHC exhaust emissions must be multiplied by the adjustment
factor used for certification of the test group, or another adjustment factor acceptable to the Administrator, to determine the equivalent NMOG
exhaust emission values for the test vehicle. The equivalent NMOG exhaust emission value must be used in place of
the measured NMOG exhaust emission value in determining the exhaust NMOG results. The equivalent NMOG exhaust emission values must be compared to
the NMOG exhaust emission standard
from the emission bin to which the test group was certified.

(2) For flexible-fueled LDVs, LDTs
and MDPVs certified to NMOG standards, the manufacturer may request from the Administrator the use of a methanol (M85) or ethanol (E85) NMOG exhaust emission to gasoline
NMHC exhaust emission ratio which must be established during certification
for each emission data vehicle for the applicable test group. The results must
be submitted to the Administrator in the Part II application for certification. After approval by the Administrator, the measured gasoline NMHC exhaust emissions must be multiplied by the M85 or E85 NMOG to gasoline NMHC ratio submitted in the application for certification for the test group to determine the equivalent NMOG
exhaust emission values for the test vehicle. The equivalent NMOG exhaust emission value must be used in place of
the measured NMOG exhaust emission value in determining the exhaust NMOG results. The equivalent NMOG exhaust emission values must be compared to
the NMOG exhaust emission standard
from the vehicle emission standard bin to which the test group was certified.

(3) If the manufacturer measures NMOG it must also measure and report
HCHO emissions. As an alternative to measuring the HCHO content, if the
manufacturer measures NMHC as permitted in paragraph (f)(1) of this section, the Administrator may approve,


### 6866 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

upon submission of supporting data by a manufacturer, the use of HCHO to NMHC ratios. To request the use of HCHO to NMHC ratios, the manufacturer must establish during certification testing the ratio of
measured HCHO exhaust emissions to
measured NMHC exhaust emissions for
each emission data vehicle for the applicable test group. The results must
be submitted to the Administrator with the Part II application for certification. Following approval of the application for certification, the manufacturer may conduct in-use testing on the test group by measuring NMHC exhaust emissions
rather than HCHO exhaust emissions.
The measured NMHC exhaust emissions must be multiplied by the HCHO to
NMHC ratio submitted in the application for certification for the test group to determine the equivalent
HCHO exhaust emission values for the test vehicle. The equivalent HCHO
exhaust emission values must be compared to the HCHO exhaust emission standard applicable to the test

group.

40. Section 86.1846–01 is amended by revising paragraph (a) to read as follows:

§ 86.1846–01 Manufacturer in-use confirmatory testing requirements.

(a) General requirements. (1) A manufacturer of LDVs, LDTs and/or MDPVs must test, or cause testing to be conducted, under this section when the emission levels shown by a test group sample from testing under § 86.1845–01 exceeds the criteria specified in paragraph (b) of this section. The testing required under this section applies separately to each test group and at each test point (low and high mileage) that meets the specified criteria. The testing requirements apply separately for each model year starting with model year

2001.

(2) Except for vehicles certified under the NLEV provisions of subpart R of this part or unless otherwise approved by the Administrator, no emission
measurements made under the requirements of this section may be adjusted by Reactivity Adjustment Factors (RAFs).

(3) For purposes of this section, the term vehicle includes light-dutyvehicles, light-duty trucks and mediumduty vehicles.

(4) Upon a manufacturer’s written request, prior to in-use testing, that presents information to EPA regarding pre-conditioning procedures designed solely to remove the effects of high sulfur in gasoline from vehicles produced through the 2007 model year, EPA will consider allowing such procedures on a case-by-case basis. EPA’s decision will apply to manufacturer in-use testing conducted under this section and to any in-use testing conducted by EPA.

* * * * *

41. Section 86.1848–01 is amended by adding paragraph (c)(7) to read as
follows:

§ 86.1848–01 Certification.

* * * * *

(c) * * *
(7) For Tier 2 and interim non-Tier 2 vehicles, all certificates of conformity issued are conditional upon compliance with all provisions of §§ 86.1811–04, 86.1860–04, 86.1861–04 and 86.1862–04 both during and after model year production.

(i) Failure to meet the fleet average

NO X requirements of 0.07g/mi, 0.30 g/ mi or 0.20 g/mi, as applicable, will be considered to be a failure to satisfy the terms and conditions upon which the certificate(s) was (were) issued and the
vehicles sold in violation of the fleet average NO X standard will not be covered by the certificate(s).

(ii) Failure to comply fully with the prohibition against selling credits that it has not generated or that are not available, as specified in § 86.1861–04,
will be considered to be a failure to satisfy the terms and conditions upon which the certificate(s) was (were)
issued and the vehicles sold in violation of this prohibition will not be covered by the certificate(s).

(iii) Failure to comply fully with the phase-in requirements of § 86.1811–04,
will be considered to be a failure to satisfy the terms and conditions upon which the certificate(s) was (were)
issued and the vehicles sold which donot comply with Tier 2 or interim nonTier 2 requirements, up to the number needed to comply, will not be covered by the certificate(s).

(iv) For paragraphs (c)(7)(i) through (iii) of this section:

(A) The manufacturer must bear the burden of establishing to the satisfaction
of the Administrator that the terms and conditions upon which the certificate(s) was (were) issued were satisfied.

(B) For recall and warranty purposes, vehicles not covered by a certificate of conformity will continue to be held to
the standards stated or referenced in the
certificate that otherwise would have applied to the vehicles.

* * * * *

42. Sections 86.1854 through 86.1859
are added and reserved.

43. Section 86.1860–04 is added to
read as follows: § 86.1860–04 How to comply with the Tier 2 and interim non-Tier 2 fleet average NOX standards.

(a) The fleet average standards
referred to in this section are the corporate fleet average standards for
FTP exhaust NO X emissions set forth in: § 86.1811–04(d) for Tier 2 LDV/Ts and MDPVs (0.07 g/mi); § 86.1811–04(l)(3) for interim non-Tier 2 LDV/LLDTs (0.30 g/mi); and, § 86.1811–04(l)(3) for interim non-Tier 2 HLDT/MDPVs (0.20 g/mi). Unless otherwise indicated in this section, the provisions of this section apply to all three corporate fleet average standards, except that the interim non-Tier 2 fleet average NOX standards do not apply to a
manufacturer whose U.S. LDV/T and MDPV sales are 100% Tier 2 LDV/Ts
and MDPVs.

(b)(1) Each manufacturer must comply with the applicable fleet average NOX standard, or standards, on a sales weighted average basis, at the end of each model year, using the procedure
described in this section.

(2) During a phase-in year, the manufacturer must comply with the applicable fleet average NO X standard for the required phase-in percentage for that year as specified in § 86.1811– 04(k)(1), or for the alternate phase-in percentage as permitted under § 86.1811–04(k)(6).

(c)(1)(i) Each manufacturer must separately compute the sales weighted averages of the individual NO X emission
standards to which it certified all its Tier 2 vehicles, interim non-Tier 2 LDV/ LLDTs, and interim non-Tier 2 HLDT/ MDPVs of a given model year as described in § 86.1804(l)(2).

(ii) For model years up to and including 2008, manufacturers must compute separate NO X fleet averages for
Tier 2 LDV/LLDTs and Tier 2 HLDT/

MDPVs.

(2)(i) For model years up to and including 2008, if a manufacturer
certifies its entire U.S. sales of Tier 2 or
interim non-Tier 2 LDV/LLDTs or interim non-Tier 2 HLDT/MDPVs, to full useful life bins having NOX standards at or below the applicable fleet average NO X standard, that manufacturer may elect not to compute a fleet average NO X level for that category of vehicles. A manufacturer making such an election must not generate NO X credits for that category of vehicles for that model year.

(ii) For model years after 2008, if a
manufacturer certifies its entire U.S.
sales of Tier 2 vehicles to full useful life bins having NO X standards at or below 0.07 gpm, that manufacturer may elect not to compute a fleet average NOX level
for its Tier 2 vehicles. A manufacturer


### 6867 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

making such an election must not generate NO X credits for that model

year.

(d) The sales weighted NO X fleet averages determined pursuant to paragraph (c) of this section must be compared with the applicable fleet average standard; 0.07 g/mi for NOX for Tier 2 LDV/Ts and MDPVs, 0.30 g/mi
for NO X for interim non-Tier 2 LDV/ LLDTs, and 0.20 g/mi for NOx for
interim non-Tier 2 HLDT/MDPVs. Each manufacturer must comply on an annual basis with the fleet average standards by:

(1) Showing that its sales weighted average NO X emissions of its LDV/ LLDTs, HLDT/MDPVs or LDV/Ts, as applicable, are at or below the applicable fleet average standard; or

(2) If the sales weighted average is not at or below the applicable fleet average standard, by obtaining and applying
sufficient Tier 2 NO X credits, interim
non-Tier 2 LDV/LLDT NO X credits or
interim non-Tier 2 HLDT/MDPV NO X credits, as appropriate, and as permitted under § 86.1861–04.

(i) Manufacturers may not use NMOG credits generated under the NLEV program in subpart R of this part to meet any Tier 2 or interim non-Tier 2 NOX fleet average standard. (ii) Tier 2 NO X credits may not be used to meet any fleet average interim

non-Tier 2 NO X standard except as permitted by § 86.1860–04(e)(1).

(iii) Interim non-Tier 2 NO X credits may not be used to meet the Tier 2 fleet average NO X standard.

(iv) Interim non-Tier 2 NO X credits from HLDT/MDPVs may not be used to meet the fleet average NO X standard for interim non-Tier 2 LDV/LLDTs, and
interim non-Tier 2 credits from LDV/ LLDTs may not be used to meet the fleet average NO X standard for interim nonTier 2 HLDT/MDPVs.

(e) (1) Manufacturers that cannot meet the requirements of paragraph (d) of this section, may carry forward a credit deficit for three model years, but must not carry such deficit into the fourth year. When applying credits to reduce
or eliminate a deficit under the fleet average standard for interim LDV/ LLDTs or interim HLDT/MDPVs, that has been carried forward into a year subsequent to its generation, a manufacturer may apply credits from
Tier 2 LDV/LLDTs or Tier 2 HLDT/ MDPVs, respectively, as well as from the appropriate group of interim
vehicles. A manufacturer must not use
interim credits to reduce or eliminate any NO X credit deficit under the Tier 2 fleet average standard. (2) A manufacturer carrying a credit deficit into the third year must generate
or obtain credits to offset that deficit and apply them to the deficit at a rate of 1.2:1, (i.e. deficits carried into the third model year must be repaid with credits equal to 120 percent of the deficit).

(3) A manufacturer must not bank credits for future model years or trade credits to another manufacturer during a model year into which it has carried
a deficit.

(f) Computing fleet average NO X emissions. (1) Manufacturers must separately compute these fleet NO X averages using the equation contained in paragraph (f)(2) of this section:

(i) Their Tier 2 LDV/LLDT and Tier 2 HLDT/MDPV fleet average NO X emissions for each model year through

2008;

(ii) Their combined Tier 2 LDV/T and MDPV fleet average NO X emissions for each model year after 2008;

(iii) Their interim non-Tier 2 LDV/ LLDT fleet average NO X emissions for each model year through 2006; and

(iv) Their interim non-Tier 2 HLDT/ MDPV fleet average NO X emissions for each model year through 2008.

(2) The equation for computing fleet average NO X emissions is as follows:



### (

( . ., / , N NO

e g HLDT MDPVs X 

### × 

# ∑ emission standard)

Total number of vehicles of the appropriate category all LDV/Ts and MDPVs, or interim non-Tier 2 etc.) sold including HEVs and ZEVs

Where:

N = The number of vehicles sold in the applicable category that were certified for each corresponding

NO X emission bin. N must be based on vehicles counted to the point of
first sale.

Emission standard = The individual full
useful life NO X emission standard
for each bin for which the
manufacturer had sales.

(3) The results of the calculation in paragraph (f)(2) of this section must be rounded as required by § 86.1837–01.

(4) When approved in advance by the Administrator, the numerator in the equation in paragraph (f)(2) of this section may be adjusted downward by the product of the number of HEVs from
each NO X emission bin times a HEV

NO X contribution factor determined through mathematical estimation of the
reduction in NO X emissions over the test procedure used to certify the HEVs.
The reduction in NO X emissions must be determined using good engineering judgement and reflect the relation in
actual full useful life NO X emissions to
the full useful life NO X standards for the certification bin applicable to the vehicles. The Administrator may require
that calculation of the HEV NOX contribution factor include vehicle parameters such as vehicle weight, portion of time during the test procedure that the HEV operates with zero exhaust emissions, zero emission range, NO X emissions from fuel-fired
heaters and NO X emissions from electricity production and storage.

(g) Additional credits for vehicles certified to 150,000 mile useful lives. (1) A manufacturer may certify any test group to an optional useful life of 15 years or 150,000 miles, whichever
occurs first.

(2)(i) For any test group certified to the optional 15 year/150,000 mile useful life, the manufacturer may generate
additional NO X credits, except as prohibited in paragraph (g)(3) of this

section. (ii) The manufacturer must calculate

these extra NO X credits, where permitted, by substituting an adjusted

NO X standard for the applicable NO X standard from the full useful life

certification bin when it calculates the applicable fleet average NO X emissions by the procedure in paragraph (f) of this section. The adjusted standard must be equal to the applicable full useful life

NO X standard multiplied by 0.85 and

rounded to the same number of decimal places as the applicable full useful life

NO X standard.

(3) A manufacturer electing not to comply with applicable intermediate life standards as permitted under § 86.1811–04(c)(4) may not generate

additional credits from vehicles certified to a useful life of 15 years/ 150,000 miles; except that, for bins

where such intermediate life standards do not exist or are specifically deemed to be optional in § 86.1811–04(c)(4), the manufacturer may generate additional


### 6868 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

NO X credits from vehicles certified to a useful life of 15 years/150,000 miles.

(h) Additional credits for vehicles certified to low bins. A manufacturer may obtain additional NO X credits by certifying vehicles to bins 1 and/or 2 in model years from 2001 through 2005 subject to the following requirements:

(1) When computing the fleet average

Tier 2 NO X emissions using the formula in paragraph (f)(2) of this section, the manufacturer may multiply the number (N) of vehicles certified to bins 1 and 2 by the applicable multiplier shown in Table S04–11. These multipliers may not be used after model year 2005. The
table follows:



### TABLE 

### S04–11—M ULTIPLIERS FOR 

### A D



### DITIONAL 

### T IER 

### 2 NOX 

### Credits for
Bin 1 and 2 LDV/Ts.

Bin Model year Multiplier

2 ..... 2001, 2002, 2003, 2004, 2005. 1.5

1 ..... 2001, 2002, 2003, 2004, 2005. 2.0

(2) [Reserved] 44. Section 86.1861–04 is added to
read as follows:

§ 86.1861–04 How do the Tier 2 and interim
non-Tier 2 NOX averaging, banking and trading programs work?

(a) General provisions for Tier 2
credits and debits. (1) A manufacturer whose Tier 2 fleet average NOX emissions exceeds the 0.07 g/mile standard must complete the calculation at paragraph (b) of this section to
determine the size of its NOX credit
deficit. A manufacturer whose Tier 2 fleet average NO X emissions is less than or equal to the 0.07 g/mile standard must complete the calculation in paragraph (b) of this section if it desires to generate NO X credits. In either case,
the number of credits or debits
determined in the calculation at paragraph (b) of this section must be
rounded to the nearest whole number.

(2) Credits generated according to the calculation in paragraph (b)(1) of this section may be banked for future use or
traded to another manufacturer.

(3) NO X credits are not subject to any discount or expiration date except as required under the deficit carryforward provisions of § 86.1860–04(e)(2).

(4) If a manufacturer calculates that it has negative credits (debits or a credit deficit) for a given model year, it must obtain sufficient credits, as required under § 86.1860–04(e)(2), from vehicles produced by itself or another manufacturer in a model year no later than the third model year following the model year for which it calculated the credit deficit. (Example: if a manufacturer calculates that it has a

NO X credit deficit for the 2008 model year, it must obtain sufficient NOX credits to offset that deficit from its own production or that of other
manufacturers’ 2011 or earlier model year vehicles.)

(5) A small volume manufacturer that has opted not to meet all phase-in requirements as permitted under § 86.1811–04(k)(5), must:

(i) Demonstrate compliance or obtain appropriate credits to comply with the 0.30 g/mi. fleet average NO X standard for interim LDV/LLDTs for 100% of its LDV/LLDTs in 2004, in order to carry
forward a credit deficit for later model year interim LDV/LLDTs; and

(ii) Demonstrate compliance or obtain appropriate credits to comply with the 0.07 g/mi. fleet average NO X standard for 100% of its LDV/LLDTs in 2007, in order to carry forward a credit deficit for later model year Tier 2 LDV/LLDTs; and

(iii) Demonstrate compliance or obtain appropriate credits to comply with the 0.20 g/mi. fleet average interim

NO X standard for 100% of its HLDT/ MDPVs in 2007, in order to carry
forward a credit deficit for later model year interim HLDT/MDPVs.

(6)(i) Manufacturers may not use NOX credits to comply with the NLEV requirements of subpart R of this part.

(ii) Manufacturers may not use NMOG credits generated by vehicles certified to the NLEV requirements of subpart R of this part to comply with any NOX requirements of this subpart.

(iii) Manufacturers may not use NOX credits generated by interim non-Tier 2 vehicles to comply with the fleet average NO X standard for Tier 2
vehicles.

(iv) Manufacturers may not use NOX credits generated by Tier 2 vehicles to comply with any fleet average NOX standard for interim non-Tier 2 vehicles, except as permitted under § 86.1860– 04(e).

(v) Manufacturers may not use NOX credits generated by interim non-Tier 2 LDV/LLDTs to comply with the fleet average NO X standard for interim nonTier 2 HLDT/MDPVs.

(vi) Manufacturers may not use NOX credits generated by interim non-Tier 2 HLDT/MDPVs to comply with the fleet average NO X standard for interim nonTier 2 LDV/LLDTs.

(vii) Manufacturers may not use NOX credits generated by Tier 2 LDV/LLDTs to comply with the Tier 2 NOX average standard for HLDT/MDPVs before the 2009 model year.

(viii) Manufacturers may not use NOX credits generated by Tier 2 HLDT/ MDPVs to comply with the Tier 2 NOX average standard for LDV/LLDTs before the 2009 model year.

(7) Manufacturers may bank Tier 2

NO X credits for later use to meet the Tier 2 fleet average NO X standard or
trade them to another manufacturer. Credits are earned on the last day of the model year. Before trading or carrying over credits to the next model year, a manufacturer must apply available credits to offset any credit deficit, where
the deadline to offset that credit deficit has not yet passed.

(8) There are no property rights
associated with NO X credits generated under this subpart. Credits are a limited authorization to emit the designated amount of emissions. Nothing in this Part or any other provision of law
should be construed to limit EPA’s authority to terminate or limit this authorization through a rulemaking.

(b) Calculating Tier 2 credits and
debits. (1) Manufacturers that achieve fleet average NO X values from the calculation in § 86.1860–04(f), lower than the applicable fleet average NOX standard, may generate credits for a given model year, in units of vehicle-g/

mi NO X , determined in this equation: [(Fleet Average NO X Standard)

¥ (Manufacturer’s Fleet Average NO X Value)] + (Total number of Tier 2 Vehicles Sold, Including ZEVs and HEVs)

Where: The number of Tier 2 vehicles sold is based on the point of first sale
and does not include vehicles sold in California or a state that adopts, and has in effect for that model year, California emission requirements.

(2) Where the result of the calculation in paragraph (b)(1) of this section is a negative number, the manufacturer must generate negative NO X credits (debits).

(c) Early banking. (1)(i) Manufacturers may certify LDV/LLDTs to the Tier 2 FTP exhaust standards in § 86.1811–04 for model years 2001–2003 in order to
bank credits for use in the 2004 and later model years. Such vehicles must
also meet SFTP exhaust emission standards specified in § 86.1811–04.

(ii) Manufacturers may certify HLDT/
MDPVs to the Tier 2 FTP exhaust standards in § 86.1811–04 for model years 2001–2007 in order to bank credits
for use in the 2008 and later model years. Such vehicles must also meet applicable SFTP exhaust emission standards specified in § 86.1811–04.

(iii) This process is referred to as ‘‘early banking’’ and the resultant credits are referred to as ’’early credits’’. In order to bank early credits, a manufacturer must comply with all
exhaust emission standards and requirements applicable to Tier 2 LDV/ LLDTs and/or HLDT/MDPVs, as applicable, except as allowed under paragraph (c)(4) of this section.

(2) To generate early credits, a manufacturer must separately compute


### 6869 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

the sales weighted NO X average of the
LDV/LLDTs and HLDT/MDPVs it
certifies to the Tier 2 exhaust requirements and separately compute credits using the calculations in this section and in § 86.1860–04.

(3) Early HLDT/MDPV credits may not be applied to LDV/LLDTs before the 2009 model year. Early LDV/LLDT credits may not be applied to HLDT/ MDPVs before the 2009 model year.

(4) Manufacturers may generate early Tier 2 credits from LDVs, LDT1s and
LDT2s that are certified to a full useful life of 100,000 miles, provided that the credits are prorated by a multiplicative factor of 0.833 (the quotient of 100,000/ 120,000). Where a manufacturer has both 100,000 and 120,000 mile full
useful life vehicles for which it desires to bank early credits, it must compute the credits from each group of vehicles separately and then add them together.

(5) Manufacturers may bank early
credits for later use to meet the Tier 2 fleet average NO X standard or trade them to another manufacturer subject to the restriction in paragraph (c)(3) of this

section.

(6) Early credits must not be used to comply with the fleet average NOX standards for interim non-Tier 2
vehicles.

(7) Nothing in this section prevents
the use of the NMOG values of 2003 and earlier model year LDV/LLDTs from being used in calculations of the NMOG fleet average and subsequent NMOG credit generation, under subpart R of this part.

(d) Reporting and recordkeeping for

Tier 2 NO X credits including early
credits. Each manufacturer must comply with the reporting and recordkeeping requirements of § 86.1862–04.

(e) Fleet average NO X debits. (1) Manufacturers must offset any debits for a given model year by the fleet average

NO X reporting deadline for the third model year following the model year in which the debits were generated as required in § 86.1860.04(e)(2). Manufacturers may offset debits by generating credits or acquiring credits generated by another manufacturer.

(2)(i) Failure to meet the requirements of paragraphs (a) through (d) of this section and of this paragraph (e), within the required timeframe for offsetting
debits will be considered to be a failure to satisfy the conditions upon which the certificate(s) was issued and the individual noncomplying vehicles not covered by the certificate must be determined according to this section.

(ii) If debits are not offset within the specified time period, the number of vehicles not meeting the fleet average

NO X standards and not covered by the certificate must be calculated by dividing the total amount of debits for the model year by the fleet average NOX standard applicable for the model year
in which the debits were first incurred.

(iii) EPA will determine the vehicles
for which the condition on the certificate was not satisfied by designating vehicles in those test groups with the highest certification NO X emission values first and continuing until a number of vehicles equal to the calculated number of noncomplying
vehicles as determined above is
reached. If this calculation determines that only a portion of vehicles in a test group contribute to the debit situation, then EPA will designate actual vehicles in that test group as not covered by the certificate, starting with the last vehicle produced and counting backwards.

(3) If a manufacturer ceases production of LDV/Ts and MDPVs or is purchased by, merges with or otherwise combines with another manufacturer,
the manufacturer continues to be responsible for offsetting any debits outstanding within the required time period. Any failure to offset the debits
will be considered to be a violation of paragraph (e)(1) of this section and may subject the manufacturer to an
enforcement action for sale of vehicles not covered by a certificate, pursuant to paragraph (e)(2) of this section.

(4) For purposes of calculating the statute of limitations, a violation of the requirements of paragraph (e)(1) of this section, a failure to satisfy the conditions upon which a certificate(s)
was issued and hence a sale of vehicles not covered by the certificate, all occur upon the expiration of the deadline for offsetting debits specified in paragraph (e)(1) of this section.

(f) NO X credit transfers. (1) EPA may reject NO X credit transfers if the
involved manufacturers fail to submit
the credit transfer notification in the annual report.

(2) A manufacturer may not sell
credits that are not available for sale pursuant to the provisions in paragraphs (a)(2) and (a)(7) of this section.

(3) In the event of a negative credit balance resulting from a transaction, both the buyer and seller are liable, except in cases involving fraud. EPA may void ab initio the certificates of conformity of all engine families participating in such a trade.

(4)(i) If a manufacturer transfers a credit that it has not generated pursuant to paragraph (b) of this section or acquired from another party, the
manufacturer will be considered to have generated a debit in the model year that
the manufacturer transferred the credit.
The manufacturer must offset such debits by the deadline for the annual report for that same model year.

(ii) Failure to offset the debits within the required time period will be considered a failure to satisfy the conditions upon which the certificate(s)
was issued and will be addressed pursuant to paragraph (e) of this section.

(g) Interim non-Tier 2 NO X credits and debits; Interim non-Tier 2 averaging, banking and trading. Interim non-Tier 2

NO X credits must be generated, calculated, tracked, averaged, banked, traded, accounted for and reported upon separately from Tier 2 credits. The provisions of this section applicable to

Tier 2 NO X credits and debits and Tier 2 averaging banking and trading are applicable to interim non-Tier 2 LDV/
LLDTs and interim non-Tier 2 HLDT/ MDPVs with the following exceptions:

(1) Provisions for early banking under paragraph (c) of this section do not apply.

(2) The fleet average NO X standard used for calculating credits is 0.30 grams per mile for interim non-Tier 2 LDV/LLDTs and 0.20 g/mi for interim non-Tier 2 HLDT/MDPVs. (The interim

non-Tier 2 NO X standard of 0.30 (or 0.20) g/mi replaces 0.07 in the text and calculation in this section.)

(3) Interim non-Tier 2 NO X credit deficits may be carried forward for three years subject to the requirements of § 86.1860–04(e).

45. Section 86.1862–04 is added to
read as follows:

§ 86.1862–04 Maintenance of records and

submittal of information relevant to compliance with fleet average NOX standards.

(a) Maintenance of records. (1) The manufacturer producing any light-duty vehicles and/or light-duty trucks subject to the provisions in this subpart must establish, maintain, and retain the following information in adequately organized and indexed records for each model year:

(i) Model year; (ii) Applicable fleet average NO X standard: 0.07g/mi for Tier 2 LDV/Ts; 0.30 g/mi for interim non-Tier 2 LDV/ LLDTs; or 0.20 g/mi for interim non-Tier 2 HLDT/MDPVs;

(iii) Fleet average NO X value achieved; and

(iv) All values used in calculating the fleet average NO X value achieved.

(2) The manufacturer producing any LDV/Ts or MDPVs subject to the provisions in this subpart must establish, maintain, and retain the following information in adequately organized and indexed records for each LDV/T or MDPV subject to this subpart:

(i) Model year;


### 6870 Federal Register / Vol. 65, No. 28 / Thursday, February 10, 2000 / Rules and Regulations

(ii) Applicable fleet average NO X standard;

(iii) EPA test group; (iv) Assembly plant; (v) Vehicle identification number; (vi) NO X standard to which the LDV/ T or MDPV is certified; and

(vii) Information on the point of first sale, including the purchaser, city, and

state.

(3) The manufacturer must retain all records required to be maintained under this section for a period of eight years from the due date for the annual report. Records may be retained as hard copy or reduced to microfilm, ADP diskettes, and so forth, depending on the
manufacturer’s record retention procedure; provided, that in every case
all information contained in the hard copy is retained.

(4) Nothing in this section limits the Administrator’s discretion to require the
manufacturer to retain additional
records or submit information not specifically required by this section.

(5) Pursuant to a request made by the Administrator, the manufacturer must
submit to the Administrator the
information that the manufacturer is required to retain.

(6) EPA may void ab initio a certificate of conformity for a vehicle
certified to emission standards as set
forth or otherwise referenced in this subpart for which the manufacturer fails to retain the records required in this section or to provide such information to the Administrator upon request.

(b) Reporting. (1) Each covered
manufacturer must submit an annual report. Except as provided in paragraph (b)(2) of this section, the annual report must contain, for each applicable fleet average NO X standard, the fleet average

NO X value achieved, all values required
to calculate the NO X value, the number of credits generated or debits incurred, and all the values required to calculate the credits or debits. The annual report must contain the resulting balance of
credits or debits.

(2) When a manufacturer calculates compliance with the fleet average NOX standard using the provisions in § 86.1860–04(c)(2), then the annual report must state that the manufacturer has elected to use such provision and must contain the fleet average NOX standard as the fleet average NOX value for that model year.

(3) For each applicable fleet average

NO X standard, the annual report must
also include documentation on all credit
transactions the manufacturer has engaged in since those included in the last report. Information for each
transaction must include:

(i) Name of credit provider; (ii) Name of credit recipient; (iii) Date the transfer occurred; (iv) Quantity of credits transferred;
and

(v) Model year in which the credits
were earned.

(4) Unless a manufacturer reports the data required by this section in the annual production report required under § 86.1844–01(e) and subsequent model year provisions, a manufacturer must submit an annual report for each model year after production ends for all affected vehicles and trucks produced by the manufacturer subject to the provisions of this subpart and no later than May 1 of the calendar year following the given model year. Annual reports must be submitted to: Director, Vehicle Programs and Compliance Division, U.S. Environmental Protection Agency, 2000 Traverwood, Ann Arbor, Michigan 48105.

(5) Failure by a manufacturer to submit the annual report in the specified time period for all vehicles and trucks subject to the provisions in
this section is a violation of section 203(a)(1) of the Clean Air Act for each subject vehicle and truck produced by
that manufacturer.

(6) If EPA or the manufacturer determines that a reporting error occurred on an annual report previously submitted to EPA, the manufacturer’s
credit or debit calculations will be recalculated. EPA may void erroneous credits, unless transferred, and must adjust erroneous debits. In the case of transferred erroneous credits, EPA must adjust the selling manufacturer’s credit
or debit balance to reflect the sale of such credits and any resulting generation of debits.

(c) Notice of opportunity for hearing. Any voiding of the certificate under paragraph (a)(6) of this section will be made only after EPA has offered the manufacturer concerned an opportunity for a hearing conducted in accordance with § 86.614 for light-duty vehicles or § 86.1014 for light-duty trucks and, if a manufacturer requests such a hearing, will be made only after an initial decision by the Presiding Officer.

[FR Doc. 00–19 Filed 2–9–00; 8:45 am]

BILLING CODE 6560–50–P